The World Bank FOR OFFICIAL USE ONLY

Transcription

The World Bank FOR OFFICIAL USE ONLY
Document of
The World Bank
FOR OFFICIAL USE ONLY
Report No: 53425-ZA
PROJECT APPRAISAL DOCUMENT
ON A
PROPOSED LOAN
IN THE AMOUNT OF US$3,750 MILLION
TO
ESKOM HOLDINGS LIMITED
GUARANTEED BY REPUBLIC OF SOUTH AFRICA
FOR AN
ESKOM INVESTMENT SUPPORT PROJECT
March 19, 2010
Energy Group
Sustainable Development Department
Africa Region
This document has a restricted distribution and may be used by recipients only in the performance of their
official duties. Its contents may not otherwise be disclosed without World Bank authorization.
CURRENCY EQUIVALENTS
(Exchange Rate estimated as of February 15, 2010)
Currency Unit = Rand
Rand 7.50 = US$1
FISCAL YEAR
April 1 – March 31
ABBREVIATIONS AND ACRONYMS
AfDB
AFD
AQA
AMEU
ASGI
BBEE
BEE
BER
BID
BOP
CAGR
CAS
CBM
CCS
CDM
CEC
CED
CEO
CFAA
CFLs
COO
CPA
CPAR
CPIA
CPI
CPS
CPF
CSDP
CTA
CSP
CTA
CTF
CTL
DA
DEAT
DBSA
DCCSF
DFID
DMEDNA
DNA
African Development Bank
Agence Française de Développement
Air Quality Act of 2004
Association of Municipal Electricity Undertakings
Accelerated Share Growth Initiative
Broad Based Black Economic Empowerment
Black Economic Empowerment
Bureau of Economic Research
Background Information Document
Balance of Payments
Compound Annual Growth Rate
Country Assistance Strategy
Coal Bed Methane
Carbon Capture and Sequestration
Clean Development Mechanism
Committee for Environmental Coordination
Capital Expansion Department
Chief Executive Officer
Country Financial Accountability Assessment
Compact Fluorescent Lamps
Chief Operating Officer
Criminal Procedure Act
Country Procurement Assessment Review
Country Policy and Institutional Assessment
Consumer Price Index
Country Partnership Strategy
Carbon Partnership Facility
Competitive Supplier Development Program
Coal Transport Agreement
Concentrating Solar Power
Coal Transport Agreement
Clean Technology Fund
Coal-to-Liquid
Disbursement Account
Department of Environment and Tourism
Development Bank of Southern Africa
Development and Climate Change Strategic
Framework
United Kingdom Department for International
Development
Department of Minerals and Energy Designated
National Authority
Designated National Authority
DNI
DPE
DSM
DST
DoE
DoEA
DWAF
EA
EBITDA
ECA
ECAs
EDI
EDPL
EE
EGEAS
EGF
EIA
EIB
EIRR
EMF
EMP
ENPV
EPP
ERR
EU
FBE
F&C
FDI
FBE
FGD
FIRR
FM
GDP
GEF
GHG
GNP
GNI
GoSA
IBRD
ICR
ICB
Direct Normal Insulation
Department of Public Enterprises
Demand Side Management
Department of Science and Technology
Department of Energy
Department of Environmental Affairs
Department of Water Affairs
Environmental Assessment
Earnings Before Interest, Taxes, Depreciation and
Amortization
Environmental Conservation Act
Export Credit Agencies
Electricity Distribution Industry Holdings
Electricity Sector Development Policy Loan
Energy Efficiency
Electric Generation Expansion Analysis System
Electrical Generation Facilities
Environmental Impact Assessment
European Investment Bank
Economic Internal Rate of Return
Environmental Management Framework
Environmental Management Plan
Economic Net Present Value
Electricity Pricing Policy
Economic Rate of Return
European Union
Free Basic Electricity
Fraud and Corruption
Foreign Direct Investment
Free Basic Electricity
Flue Gas Desulphurization
Financial Interest Rate of Return
Financial Management
Gross Domestic Product
Global Environment Facility
Greenhouse Gas
Gross National Product
Gross National Income
Government of South Africa
International Bank for Reconstruction and
Development
Implementation & Completion Results Report
International Competitive Bidding
IEP
IFC
IFI
IFR
IGCC
IMF
IP
IPFA
IPP
IRP
ISEP
KfW
JSAN
LDP
LNG
LRMC
LTMS
MDGs
MET
MEU
MFMA
MIC
MoE
MoF
MoH
MPC
MPT
MTBPS
MTEF
MTPPP
MYPD
NCB
NEDLAC
NEEA
NEMA
NEPAD
NERSA
NERT
NGL
NIPP
NIRP
NPV
NT
OCGT
OHSP
Integrated Energy Planning
International Finance Corporation
International Financing Institutions
Interim Financial Reports
Integrated Gasification Combined Cycle
International Monetary Fund
Investment Plan
Institute for Public Finance and Auditing
Independent Power Producer
Integrated Resource Planning
Integrated Strategic Electricity Plan
Kreditanstalt für Wiederaufbau
Joint Staff Advisory Note
Letter of Development Policy
Liquid Natural Gas
Long Run Marginal Cost
Long Term Mitigation Strategy/Scenario
Millennium Development Goals
Medupi Execution Team
Municipal Electric Utilities
Municipal Finance Management Act of 2004
Middle Income Countries
Ministry of Education
Ministry of Finance
Ministry of Health
Monetary Policy Commission (SARB)
Medupi Project Team
Mid-Term Budget Policy Statement
Medium-Term Expenditure Framework
Medium Term Power Purchase Program
Multi Year Price Determination
National Competitive Bidding
National Economic Development and Labor Council
National Energy Efficiency Agency
National Environment Management Act 1998
New Partnership for Africa’s Development
National Energy Regulator of South Africa
National Electricity Response Team
National Gas Liquids
National Industrial Participation Program
National Integrated Resource Plan
Net Present Value
National Treasury
Open Cycle Gas Turbine
Occupational Health and Safety Management Plan
Vice President:
Country Director:
Sector Director:
Sector Manager:
Task Team Leaders:
PDD
PEFA
PFM
PFMA
PMI
PPA
PPIAF
RAP
RE
RED
REFIT
REMT
RoA
RoCE
ROD
RoE
ROSC
RPF
SAAQIS
SACU
SADC
SANS
SAPP
SARB
SARS
SBD
SDR
SEA
S&I
SIL
SOE
SME
SSA
TFA
UCG
UCSP
UNFCC
UMIC
WM
WBG
WTP
WPP
Project Development Department
Public Financial Management Assessment
Public Financial Management
Public Financial Management Act
Purchasing Managers Index
Power Purchase Agreement
Public Private Infrastructure Advisory Facility
Resettlement Action Plan
Renewable Energy
Regional Energy Distribution/Distributor
Renewable Feed-in Tariff
Renewable Energy Market Transformation Project
Return on Assets
Return on Capital Employed
Record of Decision
Return on Equity
Report on the Observance of Standards and Codes
Resettlement Policy Framework
South African Air Quality Information System
Southern Africa Customs Union
Southern Africa Development Community
South Africa National Standards
Southern African Power Pool
South African Reserve Bank
South African Revenue Service
Standard Bidding Document
Safeguards Diagnostic Review
Strategic Environmental Assessment
Supply & Install
Specific Investment Loan
State Owned Enterprise
Small and Medium Enterprise
Sub-Saharan Africa
Transnet Freight Rail
Underground Coal Gasification
Upington Concentrating Solar Power plant
United Nations Framework Convention on
Climate Change
Upper Middle Income Countries
Waste Management
World Bank Group
Willingness To Pay
Wind Power Plant
Obiageli Katryn Ezekwesili
Ruth Kagia
Inger Andersen
Subramaniam V. Iyer
Reynold Duncan and Pankaj Gupta
SOUTH AFRICA
ESKOM INVESTMENT SUPPORT PROJECT
CONTENTS
Page Introduction ................................................................................................................................................. 1 I. STRATEGIC CONTEXT AND RATIONALE ............................................................................... 2 A. Country and sector issues ................................................................................................................ 3 B. Rationale for Bank Involvement .................................................................................................... 21 C. Higher level objectives to which the project contributes ............................................................... 27 II. PROJECT DESCRIPTION ............................................................................................................ 27 A. Lending instrument ........................................................................................................................ 27 B. Project development objective and key indicators......................................................................... 28 C. Bank strategy for support to Eskom and project components ....................................................... 28 D. Lessons learned and reflected in the project design....................................................................... 33 E. Alternatives considered and reasons for rejection ......................................................................... 34 III. IMPLEMENTATION...................................................................................................................... 37 A. Partnership arrangements............................................................................................................... 37 B. Institutional and implementation arrangements ............................................................................. 38 C. Monitoring and evaluation of outcomes/results............................................................................. 40 D. Sustainability ................................................................................................................................. 41 E. Critical risks and possible controversial aspects............................................................................ 41 F. Loan/credit conditions and covenants............................................................................................ 43 IV. APPRAISAL SUMMARY............................................................................................................... 47 A. Economic and financial analyses ................................................................................................... 47 B. Technical ....................................................................................................................................... 56 C. Fiduciary ........................................................................................................................................ 59 D. Social ............................................................................................................................................. 66 E. Environment .................................................................................................................................. 69 F. Safeguard policies .......................................................................................................................... 77 G. Policy Exceptions and Readiness .................................................................................................. 77 Annex 1: Country and Sector or Program Background ....................................................................... 79 Annex 2: Major Related Projects Financed by the Bank and/or other Agencies ............................. 109 Annex 3: Results Framework and Monitoring..................................................................................... 110 Annex 4: Detailed Project Description .................................................................................................. 113 Annex 5: Project Costs ........................................................................................................................... 129 Annex 6: Implementation Arrangements ............................................................................................. 131 Annex 7: Financial Management and Disbursement Arrangements ................................................. 139 Annex 8: Procurement Arrangements .................................................................................................. 149 Annex 9: Economic Analysis .................................................................................................................. 163 Annex 10: Financial Analysis................................................................................................................. 188 Annex 11: Safeguard Policy Issues ........................................................................................................ 203 Annex 12: Project Preparation and Processing ................................................................................... 219 Annex 13: Documents in the Project File ............................................................................................. 221 Annex 14: Statement of Loans and Credits .......................................................................................... 221 Annex 15: Country at a Glance ............................................................................................................. 223 Annex 16: Maps (IBRD 37164R & 37482) ............................................................................................ 230 SOUTH AFRICA
ESKOM INVESTMENT SUPPORT PROJECT
PROJECT APPRAISAL DOCUMENT
AFRICA
AFTEG
Team Leaders: Reynold Duncan and Pankaj Gupta
Sectors: Power (90%), Transport (10%)
Themes: Infrastructure services for private sector
development (40%); Climate change (20%);
Regulation and competition policy (20%);
Education for the knowledge economy (20%)
Environmental category: Full Assessment
Joint IFC: No
Joint Level: N/A
Date: March 19, 2010
Country Director: Ruth Kagia
Sector Manager/Director: Subramaniam V. Iyer /
Inger Andersen
Project ID: P116410
Lending Instrument: Specific Investment Loan
Project Financing Data
[X] Loan [ ] Credit [ ] Grant [ ] Guarantee
[ ] Other:
For Loans/Credits/Others:
Total Bank financing (US$ million): 3,750.00
Proposed terms: A US Dollar denominated, commitment linked, level repayment, IBRD Flexible
Loan with a variable spread, with a 7 year Grace Period and 28.5 years Final Maturity, with all
conversion options selected with repayment dates of May 1 and November 1 of each year.
Project Financing Plan (US$m)
Source
Local
Foreign
Total
Borrower
3,315.74
1,421.03
4,736.77
International Bank for Reconstruction and Development
2,266.90
1,483.10
3,750.00
Clean Technology Fund – Component B: Renewable
252.00
98.00
350.00
Energy Investments Only
Foreign Multilateral Institutions
1,917.94
745.86
2,663.80
Other Bilateral and Commercial Lenders
1,700.10
661.15
2,361.25
Total:
9,452.68
4,409.14
13,861.82
Guarantor:
Borrower:
Department of Public Enterprises, Government of Eskom Holdings
South Africa
Megawatt Park, Maxwell Drive, Sunninghill,
1090 Infotech Building, Arcadia Street, Hatfield,
Sandton, South Africa
Pretoria, South Africa
Email: [email protected]
Fax: +27 12 323 3263
Tel: +27 11 800 2901
Projected Disbursements
(IBRD Loan)
Annual (US$ million)
Cumulative (US$ million)
FY10
FY11
FY12
FY13
FY14
FY15
498.59
498.59
687.5
1186.09
862.5
2048.59
637.5
2686.09
637.5
3323.59
426.41
3750.00
i
Does the project depart from the CAS in content or other significant respects?
Ref. PAD I.C.
Does the project require any exceptions from Bank policies?
Ref. PAD IV.G.
Have these been approved by Bank management?
Is approval for any policy exception sought from the Board?
Does the project include any critical risks rated “substantial” or “high”?
Ref. PAD III.E.
Does the project meet the Regional criteria for readiness for implementation?
Ref. PAD IV.G.
[ ]Yes [X] No
[X]Yes [ ] No
[X]Yes [ ] No
[X]Yes [ ] No
[X]Yes [ ] No
[X ]Yes [ ] No
Project development objective Ref. PAD II.C., Technical Annex 3
The Project Development Objective (PDO) is to enable Eskom South Africa to enhance its power supply
and energy security in an efficient and sustainable manner so as to support both economic growth
objectives and South Africa’s long term carbon mitigation strategy.
Project description Ref. PAD II.D., Technical Annex 4
Component A: IBRD support of about US$3,040 million for the financing of the Medupi coal-fired power
plant (4,800 MW using supercritical technology). This loan will finance supply & install and construction
contracts for the power plant and associated transmission lines. Interest during Construction, payable to
IBRD and to other lenders to the project will also be financed by the proposed IBRD loan.
Component B: IBRD Support of about US$260 million for financing investments in renewable energy
(Wind and Concentrating Solar Power Plants).
Component C: IBRD support of about US$440 million for other low carbon energy efficiency
components comprising the Majuba Rail Project (railway for coal transportation) and a technical
assistance program for improving supply side efficiencies.
As per the request from the Borrower, Eskom Holding, an allocation for US$ 9.375 million has been
made to finance the US$ 9.375 million Front End Fee associated with the IBRD Loan.
Which safeguard policies are triggered, if any? Ref. PAD IV.F., Technical Annex 11
The current assessment is that the following safeguard policies are triggered: Environmental Assessment
(OP 4.01), Natural Habitats (OP 4.04), Physical Cultural Resources (OP 4.11) and Involuntary
Resettlement (OP 4.12) and Projects on International Waterways (OP 7.50). The first three of these
safeguard policies are being addressed through OP/BP 4.00, Piloting the Use of Borrower Systems to
address environmental and social safeguard issues in Bank supported projects. In line with OP 4.00, a
Safeguards Diagnostic Review (SDR) has been prepared. The SDR has been disclosed consistent with
Bank policies for disclosure for this Category A project. In keeping with best practice, all Environmental
Impact Assessments (EIAs) and Environmental Management Plans (EMPs) for the project, which have
already been disclosed to meet requirements in-country, have also been disclosed via the Infoshop. OP
7.50 is not included under OP/BP 4.00 (Piloting the Use of Borrower Systems) and issues related to
international waterways have been addressed by application of specific Bank Policy - OP 7.50.
Significant, non-standard conditions, if any, for: Ref. PAD III.F.
Board presentation: April 8, 2010
Loan/credit effectiveness: April 20, 2010
Closing date: October 31, 2015
ii
Conditions for Effectiveness of the Loans:
(a) Standard Conditions;
(b) execution and delivery of the Guarantee Agreement, and all conditions precedent to its
effectiveness (other than the effectiveness of the Loan Agreement) have been fulfilled;
(c) a special legal opinion satisfactory to the Bank of an independent counsel acceptable to the Bank
in connection with certain aspects of the Guarantor’s Anti-Corruption Legislation framework.
Conditions for Disbursement:
(a) Conditions for payments of Past Contracts under component 1 of the Project:
 the Bank’s has to be satisfied that the contractor or sub-contractor who has been awarded a Past
Contract was not debarred, or suspended by the Bank at the time when the contract award was
made; and
 the Bank has determined that: (a) the amendments to the Past Contracts to include the Bank’s
Anti-corruption and right to audit provisions are in form and substance satisfactory to the Bank;
and (b) its due diligence review of procurement decisions in connection with the Past Contracts
has been completed in a satisfactory manner.
(b) Conditions for payments of Future contracts under component 2 of the Project:

the Bank has to be satisfied that adequate funds are available to the Borrower to finance the
second component of the Project from other sources than the Loan on terms and conditions
consistent with the obligations of the Borrower under this Loan Agreement.
IBRD Loan Covenants:
Specific Anti-Corruption Covenants for Past Contracts under Part A of the Project (Medupi Power Plant)
(a)
Except as the Bank may otherwise agree in writing, and with regard to all Past Contracts, the
Borrower shall negotiate and amend each such contract to include the Audit Right and Fraud and
Corruption Provisions in conformity with the Anti-Corruption Guidelines and as such provisions are
reflected in the Bank’s Standard Bidding Documents, including, inter alia, the definition of sanctionable
practices included in the said Anti-Corruption Guidelines and Standard Bidding Documents and the
Bank’s right to sanction a firm or individual determined by it to have engaged in any such sanctionable
practice during the bid, award or implementation of a given Past Contract.
(b)
Without limitation upon the provisions of [paragraph 1 of this Section] and with regard to all Past
Contracts:
(i)
the Borrower shall promptly, by notice in writing, inform the Bank regarding any
information in its possession, including non-frivolous allegations that reasonably may point to the
possibility of the occurrence of any corrupt, fraudulent, coercive, collusive and/or obstructive
practice in connection with the bidding process, the award, or implementation of any contract to
be or being financed out of the proceeds of the Loan, as these terms are understood under the
Bank’s Anti-Corruption Guidelines or the relevant Anti-Corruption Legislation. To this end, all
such information shall be provided to the appropriately named official(s) of the Bank;
(ii)
the Borrower shall, following due consultation with the Bank, promptly take all
appropriate action in accordance with the Anti-Corruption Legislation to commence an
investigation in connection with the information referred to in sub-paragraph (i) of this paragraph
and any information provided to the Guarantor by the Bank regarding allegations of corrupt,
fraudulent, coercive, collusive and/or obstructive practice in connection with the bidding process,
the award, or implementation of any contract to be or being financed out of the proceeds of the
Loan, as these terms are understood under the Bank’s Anti-Corruption Guidelines;
(iii)
in the event that the investigation referred to in sub-paragraph (ii) of this paragraph
iii
confirms that either a corrupt, fraudulent, collusive, coercive and/or obstructive practice has
occurred, the Borrower shall promptly take timely and appropriate action to implement the
findings of such investigation and enforce the applicable remedies, in accordance with the AntiCorruption Legislation and share with the Bank evidence or any other information identified or
discovered during such investigation in connection with any such contract, it being understood
that the Bank will keep such information confidential in accordance with confidentiality
procedures that apply to its own investigations;
(iv)
the Borrower shall, in writing, adequately and regularly and, in any event, no less
frequently than quarterly, commencing with the date on which such allegations were received by
the Borrower, inform the Bank regarding any subsequent action taken pursuant to the
investigation referred to in sub-paragraph (ii) of this paragraph, and the result of enforcement of
any remedies referred to in sub-paragraph (iii) of this paragraph, including any monies that may
be recovered as a result of such action; and
(v)
in the event that the Bank may, pursuant to information referred to in sub-paragraph (i) of
this paragraph, and investigations referred to in sub-paragraph (ii) of this paragraph, determine
that a corrupt, fraudulent, collusive, coercive and/or obstructive practice, or any sanctionable
practice has occurred in connection with any Past Contract, the Bank shall have the option, in its
absolute discretion, to cancel the portion of the proceeds of the Loan allocated to such contract, or
require the Borrower to reimburse any amount that has been disbursed out of the proceeds of the
Loan under such Past Contract.
Environmental and Social Safeguards
1.
The Borrower shall implement the Project in accordance with the provisions of the
Environmental Legislation, the Social Legislation, the RODs, the EIA, the EMP, the RPF, the RAPs, if
any RAPs are required in accordance with the RPF, and the provisions of this Agreement. Without
limiting the generality of the foregoing, the Borrower shall exercise regular monitoring to ensure that
emissions from the Medupi Power Plant remain in compliance with the provisions of applicable
Environmental Legislation and all the terms of the ROD referred to in paragraph 206 of the SDR.
2.
The Borrower shall:
(a) not later than June 30, 2013, develop, adopt and thereafter implement a program, satisfactory
to the Bank, to install FGD equipment in each of the six power generation units of the Medupi
Power Plant, taking into account technical, environmental and financial criteria in accordance
with terms of reference to be discussed with the Bank, such program to be designed such that the
installation of the FGD equipment for the first power generation unit shall commence on the later
of (i) the sixth anniversary of the Commissioning Date or (ii) March 31, 2018 or such later date
as the Bank may establish following consultations with the Borrower), and, thereafter, continue
the installation of the FGD equipment sequentially, in each case thereafter at the time each of the
remaining five power generation units is taken out of service for the first major planned outage, it
being understood and agreed that all the FGD equipment for the six power generation units shall
be installed and fully operational not later than December 31, 2021, or such later date as the
Bank may establish following the said consultations with the Borrower; and
(b) afford the Bank a reasonable opportunity to exchange views with the Borrower on such FGD
installation program at each of its preparation and implementation phases.
3.
The Borrower shall refrain from carrying out any Project activity that would result in the
involuntary resettlement of any person or group of persons residing in the selected site for each of the
Borrower’s UCSP, Sere Wind Power and Majuba Rail and Transmission projects (all described under
Parts B and C of the Project); provided, however, that if such involuntary resettlement would be
unavoidable, then the Borrower shall implement such Project activities in accordance with the provisions
iv
of the RPF, including the preparation, adoption and implementation of one or more RAPs as appropriate,
all in accordance with the provisions of the Social Legislation as described in the SDR, including without
limitation, consultation with potentially Displaced Persons and disclosure of the RAPs.
4.
Not later than one year after completion of the implementation of a RAP, the Borrower shall
cause an audit to be conducted by an independent qualified resettlement expert to monitor the outcomes
of the RAP, including a survey and consultation with Displaced Persons, and which audit shall also define
any necessary action to address any shortcomings in the implementation of said RAP.
5.
The Borrower shall, not later than 45 days after the end of each calendar semester, furnish to the
Bank reports in form and substance satisfactory to the Bank, showing the volume of the water available
for the Medupi Power Plant, and the use thereof. The first such report shall be submitted to the Bank
within six months of the Commissioning Date.
6.
Except as the Bank shall otherwise agree, the Borrower shall not amend, abrogate or waive any
provision of any of the RODs, if such amendment, abrogation or waiver may, in the opinion of the Bank,
materially and adversely affect the implementation of the Project, or a substantial part thereof.
IBRD Guarantee Agreement (Government Undertakings):
Safeguards
The Guarantor specifically undertakes to:
(a)
complete the Environmental Management Framework (EMF) for the Guarantor’s Waterberg
district in compliance with the Environmental Legislation;
(b)
provide a copy of the draft final EMF to and afford an opportunity to the Bank to provide a
feedback to the Guarantor on the said EMF;
(c)
adopt the EMF and implement, the applicable policies and plans that are developed consequent to
the said EMF, and cause other parties to implement their projects and activities in compliance with the
guidelines for environmental management adopted through the said EMF, policies and plans;
(d)
ensure that the Record of Decisions for the Medupi Power Plant, the Upington Concentrating
Solar Power plant, the Sere Wind Power and the Majuba Railway and Transmission projects and, when it
is issued, for the transmission system associated with the Medupi Power Plant, as well as the mitigation
measures set forth and to be set forth therein, are implemented and adhered to;
(e)
take timely action to ensure adequate supply of water to the Medupi Power Plant for the
operations of the Borrower’s six units, including the FGD units; and
(f)
inform the Bank of, and consult with the Bank on, any proposal to modify any of the RODs if, in
the opinion of the Bank, the application of such proposal would result in material and adverse
environmental or social impacts upon the Project or any substantial part thereof.
Anti-Corruption
The Guarantor specifically undertakes:
(a)
promptly, by notice in writing, to inform the Bank regarding any information in its possession,
including non-frivolous allegations that reasonably may point to the possibility of the occurrence of any
corrupt, fraudulent, coercive, collusive and/or obstructive practice in connection with the bidding process,
the award, or implementation of any contracts to be or being financed out of the proceeds of the Loan, as
these terms are understood under the Bank’s Anti-Corruption Guidelines or the relevant Anti-Corruption
Legislation. To this end, all such information shall be provided to the appropriately named official(s) of
the Bank;
(b)
following consultations with the Bank, to promptly take all appropriate action in accordance with
v
the Anti-Corruption Legislation to commence an investigation in connection with the information referred
to in sub-paragraph (a) of this paragraph and any information provided to the Guarantor by the Bank
regarding allegations of corrupt, fraudulent, coercive, collusive and/or obstructive practice in connection
with the bidding process, the award, or implementation of any contract to be or being financed out of the
proceeds of the Loan, as these terms are understood under the Bank’s Anti-Corruption Guidelines;
(c)
in the event that the investigation referred to in sub-paragraph (b) of this paragraph confirms that
either a corrupt, fraudulent, collusive, coercive and/or obstructive practice has occurred, to promptly take
timely and appropriate action to implement the findings of such investigation and enforce the applicable
remedies, in accordance with the Anti-Corruption Legislation and share with the Bank evidence or any
other information identified or discovered during such investigation in connection with any such contract;
it being understood that the Bank will keep such information confidential in accordance with
confidentiality procedures that apply to its own investigations;
(d)
to adequately and regularly and, in any event, no less frequently than quarterly, commencing with
the date on which such allegations were received by the Guarantor, inform the Bank regarding any
subsequent action taken pursuant to the investigation referred to in sub-paragraph (b) of this paragraph,
and the result of enforcement of any remedies referred to in sub-paragraph (c) of this paragraph, including
any monies that may be recovered as a result of such action; and
(e)
in the event that the Bank may, pursuant to information referred to in sub-paragraph (a) of this
paragraph, and investigations referred to in sub-paragraph (b) of this paragraph, determine that a corrupt,
fraudulent, collusive, coercive and/or obstructive practice, or any sanctionable practice has occurred in
connection with any Past Contract, the Bank shall have the option, in its absolute discretion, upon
notification to the Borrower and the Guarantor to cancel the portion of the proceeds of the Loan allocated
to such contract, or require the Borrower to reimburse any amount that has been disbursed out of the
proceeds of the Loan under such Past Contract.
Financial Undertakings
If the Borrower has failed to perform its obligation under the Financial Undertakings of the Borrower
under the Loan Agreement, then the Bank may issue to the Borrower a notice pursuant to paragraph
7.02(b)(i) of the General Conditions (Notice of Suspension). If such failure to perform continues for a
period of sixty days after such Notice of Suspension, then the Bank may issue to the Borrower a notice of
default pursuant to paragraph 7.06(b)(i) of the General Conditions (Notice of Event of Acceleration). The
Bank may, at any time thereafter, during the continuance of such event, notify the Guarantor of such
default, continuance and potential acceleration, which notice shall include a period of one hundred and
twenty days, or such longer period as the Bank may agree, if the Bank elects to make a demand upon the
Guarantor.
vi
INTRODUCTION
1.
After several years of sustained economic growth in South Africa, supported by reliable and
sufficient electricity supply, the country’s electricity system has fallen under considerable strain.
Major capacity constraints came to a head in late-2007/early-2008 seriously affecting the performance
of the overall economy. The impact on the country's economy was immediate, driving increased
unemployment with the associated poverty impacts, forcing businesses to close, and leading to
shutdown of the largest mine operators, thus putting thousands of additional jobs at risk. This led to a
downward revision of GDP growth (see Paragraph 29), a trend reinforced by the global
financial/economic crisis. The energy crisis of 2007/08 also had serious consequences for the
Southern African region as a whole, which has long relied on South Africa for electricity supply, trade,
and investment.
2.
In response to the supply shortfall, Eskom Holdings (parastatal utility) has embarked upon an
Investment Program that entails an investment commitment of US$50 billion over a 5-year period. The
new generating capacity (part of it to be supported by the proposed project) when commissioned will
account for nearly 12.5 percent of the current generation capacity in South Africa. Any delay in its
implementation will have serious impacts on the ability of the South African government to continue
expanding electricity access to the remaining nearly 20% of the population that remain unconnected
today as power generation would be too severely constrained. Delays would also severely impact on
the South African economy as well as the sub-region (Paragraph 30).
3.
In pursuing this investment, the Government of South Africa (GoSA) is also acting on the
country’s commitment to the climate change agenda which requires prompt transition to a low carbon
economy. Consistent with this, South Africa has made a number of commitments to low carbon
growth, including: signing the Kyoto Protocol, adopting a national Climate Change Response Strategy,
issuing regulations for energy efficiency and incentivizing private participation in clean energy,
issuing air quality standards, and adopting a renewable energy target of 1,667 MW equivalent of
electricity demand by 2013. Further, in 2008, the Cabinet endorsed South Africa’s Long Term
Mitigation Scenario which targets 34 percent reduction in emissions by 2020 and 44 percent reduction
by 2025.1 This credible commitment takes account of urgent generation expansion, while committing
to an aggressive program to lower the carbon trajectory through energy efficiency, demand side
management, and adopting renewable and nuclear energy. The present project, as well as the longer
term partnership envisaged between the government of South Africa and the World Bank will enable
the country to achieve a low carbon trajectory.
4.
However, as this PAD will demonstrate, South Africa has no viable alternative to coal in
seeking to meet urgent generation needs. Further, the massive financing needs, compounded by the
constrained fiscal space as a result of the downturn, calls for IBRD’s unprecedented support as a
“lender of last resort.”
5.
The economic and development rationale for the proposed project is strong and
straightforward. Faster GDP growth has been the main policy platform of successive post-apartheid
governments, to which the current Government has added a stronger emphasis on job creation and
more shared growth. Neither objective is meaningfully attainable without tackling the manifest
electricity crisis, which clearly demonstrated that the economy had plateaued at existing energy supply
levels. While the global economic crisis temporarily eased the supply-demand gap in electricity
generation, electricity shortages, unless urgently addressed, are bound to hold back growth and, even
more significantly, job creation.
1
The ministers of energy and public enterprises have publically reiterated GoSA’s strong commitment to meeting long-term
climate change objectives and advancing renewable energy (Press Release of March 12, 2010).
1
Box 1: Energy, Employment, Poverty Reduction and Improved Welfare
Electricity as a necessary condition for growth. South Africa has one of the most energy-intensive economies among the
Middle Income Countries (MICs) – this was amply demonstrated by the 2007/08 power crisis, which proved to be a
controlled experiment to assess the importance of adequate electricity for growth. Almost overnight, the country experienced
major load-shedding, causing serious economic disruption with associated social impacts. Thousands of jobs were lost and
GDP growth fell to 1.7 percent in 2008Q1, the lowest in more than six years, as mining output fell 26 percent, the sharpest
decline on record, and manufacturing by 0.6 percent. It has been estimated by the consulting firm Deloitte that a 10 percent
drop in electricity supply would have reduced GDP by 0.6 percent in 2008 followed by a 1.2 percent drop in 2009. In
addition, according to the 2009 Investment Climate Assessment, the power outages in South Africa not only undercut growth,
they also make production less labor-intensive. It follows then that as the economy recovers from the global crisis, without
additional generation capacity, electricity supply will become a “binding constraint” to growth and job creation. In other
words, the economy will plateau and additional jobs will not be created: a dangerous scenario for a country with high
unemployment and high instances of social disquiet arising from pervasive exclusion.
Good growth, underpinned by reliable electricity supply, has proven to be a partially effective, albeit far-fromsufficient, instrument for tackling the high unemployment and widespread poverty in South Africa. The unemployment
rate fell from 27.1 percent in 2003 to 21.9 percent in end-2008, as 1.7 million jobs were created, benefitting from average
GDP growth of 5.3 percent during 2004-07. The poverty rate, too, fell from 58 percent to 48 percent between 2000 and 2005,
according to the Presidency, although social grants also played an important role: income inequality remained persistent at
very high levels, and, according to one estimate, rose between 1995 and 2005. Even just returning to the former 4-5 percent
growth path, with attendant benefits for poverty reduction and job creation, now hinges on additional supply of electric
power.
Adequate electricity supply, while necessary for growth, employment creation, and poverty reduction, would by no
means be sufficient. The unemployment rate before the power and financial crises may likely have already been close to
equilibrium levels (Banerji et al, 2008). In that sense, closing the electricity gap, by itself and within the existing policy
environment would still not reduce unemployment rate significantly. Reaching a growth path that creates jobs more rapidly
and reduces inequality would also depend on a number of other policy interventions, which the GoSA has currently
prioritized. These include urgently needed improvements in skills development and the investment climate for more rapid
growth in small and medium enterprises, addressing the challenges of the ‘geography of apartheid’ in urban areas as well as
land reform, to name but a few. In addition, the 2010 budget includes proposals for subsidizing the hiring of younger workers
without previous experience. This would lower the cost and risk of hiring somebody inexperienced, while also allowing the
young worker to benefit from on-the-job learning opportunities. The policies and implementation mechanisms that are needed
to attain these “sufficient conditions” for the sustained reduction of poverty and inequality are complex and are currently
being shaped by a vigorous process of political consensus-building and policy formulation within the government, which the
World Bank Group is supporting through technical assistance and advisory services.
Access to electricity as a basic need: South Africa’s mass electrification program started from the implementation of the
Reconstruction and Development Programme (RDP) in 1994. Infrastructure development, and broader access to electricity
supply in particular, has been held to be the key link from growth to broader social development (See Table 1). Since
electricity supply was not constrained until the power outages of 2007/08, its provision was seen more as an issue of basic
need and equity than of growth. Household electrification increased from 34 percent in 1993 to 81 percent in 2007. However,
the pace of new connections has declined more recently in large part because of lack of generation capacity. Expanding
generation, is therefore key if the Government’s objective of universal coverage has to be met within a reasonable time
period. How did the electrification program improve the lives of those with new connections? A 2008/9 study by the
Department of Minerals and Energy (DME) based on a survey of 3,960 households in the Limpopo, Eastern Cape, and
KwaZulu Natal provinces provides some insights. Evidence shows that access to electricity noticeably improved the lives of
people. Educational outcomes improved, as children (along with women) were spared the task of collecting wood and other
fuel, allowing time for study. More opportunities for income generation were created, as the option of cooling allowed
enterprise in perishable items. Communities felt safer at night as a result of street lighting. Interestingly, studies found that
while households switched from dry-cell batteries and paraffin to electricity for lighting and powering entertainment
appliances, they maintained widespread use of firewood for thermal energy use – mostly due to the high cost of appliances
and their heavy electricity usage, which raised the electricity bills prohibitively for households. The electrification program
also generated a total of almost 33 thousand jobs between 2001/02 and 2008/09.
6.
With unemployment in the 24-31 percent range (depending on the measure used), serious
service delivery backlogs, and a very high prevalence of HIV/AIDS, the sense of exclusion and
deprivation is palpable among large segments of the citizenry, unmistakably highlighted in a series of
recent street protests in urban townships. Increased electricity generation in the coming years is
essential if access to electricity is to be expanded to the remaining nearly 20% who still today do not
have such access. Electricity is critical if job creation is to be resumed in small and medium sized
businesses, in the manufacturing sector, through self-employment opportunities, as well as in the
2
proven mining industry. Given the vast number of unemployed, mostly youth, this represents a key
priority for the country. Further, in view of South Africa’s dominance in Sub-Saharan Africa, reliable
and expanded electricity generation is just as critical to the development outcomes of the region as a
whole.
I.
STRATEGIC CONTEXT AND RATIONALE
A.
Country and sector issues
Country Context
7.
South Africa’s smooth and peaceful political transition to constitutional democracy along a
negotiated path of reconciliation has been one of the most remarkable political achievements of our
time. Efforts to build a free, diverse, non-racial, and economically stronger nation have produced
impressive results although many challenges still remain. A sustained record of macroeconomic
prudence and a supportive global environment enabled South Africa’s GDP to grow at a reasonable
pace in the 10 years up to 2008. The country has also made notable strides in expanding access to
basic services such as education, health, electricity, housing, water and sanitation (see Table 1 below).
South Africa has now become the regional economic powerhouse, and its progress has led to similar
gains in many of its neighboring countries. The country’s economic dominance has provided it a
2
natural leadership role on the African continent, a mantle it has worn with responsibility. Notably,
South Africa is a leader in Africa’s dialogue and position on climate change and has taken a leadership
position in co-drafting and signing the Copenhagen Accord (COP 15).
Table 1: Access to Electricity and Water
Households
1996
2001
2007
58
47
45
70
51
49
80
67
59
62
74
61
88
70
52
59
52
73
60
Using Electricity (%)
for lighting
for cooking
for heating
Water (%)
Equivalent to or above RDP standard (200 m to communal tap)
Tap in dwelling or on site
Sanitation (%)
Equivalent to or above RDP standard
Flush toilet
Source: “Towards a Fifteen Year Review,” Policy Coordination and Advisory Services (PCAS), the Presidency, South Africa.
8.
At the same time, the benefits of growth have bypassed major segments of the population
largely because of a disappointing record on job creation, perpetuating South Africa’s record on
inequality and exclusion. These challenges are central to the priorities GoSA. An important reason has
been that the legacy and social structures of apartheid have proven troublingly long-lasting, even
though their legal foundations are no longer in place. Many are now finding it difficult to break
through the segmented structure of the economy because of very limited opportunities under the old
regime to accumulate capital in any form (land, financial, skills, education, or social networks) so
necessary for enterprise. Post apartheid governments have significantly expanded access to basic
services, but the quality and reliability of that access has proven very uneven. Despite noticeable gains
3
in poverty reduction, pockets of poverty remain deeply entrenched mostly among the black
2
South Africa is one of the driving forces behind the New Partnership for African Development (NEPAD) and the African
Peer Review Mechanism, and an anchor of other key regional partnerships (African Union, SADC, and SACU).
Internationally, it is a leading developing country participant in most multilateral fora, and was the chair of the G-20 in 2007.
3
The poverty rate fell from 58 percent to 48 percent between 2000 and 2005, as per the “Towards an Anti-Poverty Strategy
for South Africa,” by the Office of the President, South Africa, October 2008.
3
population, whose median income is just 8 percent of the median white South African.4 As a result,
South Africa is a dual economy with one of the highest inequality rates in the world, where the
impoverished living conditions of a large proportion of the black population coexist with the “firstworld” lifestyle of a segment of the multi-racial population.
Economic and Social Development: Past Performance and Critical Challenges
9.
Economic performance has significantly improved since the mid-1990s. In the period
leading up to 1994, the economy, crippled by external sanctions and policy distortions, was
characterized by low growth, high inflation, and ballooning public debt. Economic performance has
since improved markedly, underpinned by macroeconomic stabilization, firmer control of inflation
through the monetary policy of inflation-targeting, and impressive fiscal consolidation, thus ensuring
sustainability of public sector finances. The GDP grew from an annual average of 1 percent in the
decade preceding 1994 to 2.7 percent during 1994-98 and 4.1 percent during 1999-08, resulting in a 50
percent increase in GDP in the latter period. This took South Africa’s per-capita Gross National
Income (GNI) to just under US$6,000 in 2008, further consolidating its position in the ranks of Upper
Middle-Income Countries (UMIC).
10.
Macroeconomic stabilization contributed to the impressive turnaround in economic
performance. Improvements in the quality of public budget management played an especially
important role. Fiscal balances consistently improved, eventually turning into a small budget surplus
for the first time in 2007/08, causing central government debt to fall from 46 percent of GDP in 1994
to 27 percent in 2008. At the heart of the fiscal achievements were dramatic improvements in revenue
collection resulting from a more efficient South African Revenue Service (SARS).5 Exemplary
expenditure management also proved important. The 2008 Open Budget Index prepared by the
International Budget Partnership ranked South Africa second after the United Kingdom, ahead of
France, New Zealand and the United States.6,7 Acknowledgement of this record by global investors
has enabled the country to tap into international bond markets with reasonable sovereign risk spreads.8
11.
Fiscal space generated through budgetary discipline was prudently used for pro-poor
and infrastructure-related expenditure. Access to basic expenditure expanded such as education,
health, housing and sanitation. Increased capital spending has focused on improving the provision of
basic utility services to schools and clinics, and construction, rehabilitation and maintenance of
national and provincial roads. The social grant system has seen a dramatic increase in coverage: from
2.5 million beneficiaries in 1999 to over 13 million in 2009. The grants are mostly for child support
(where coverage increased from just 34 thousand in 1999 to 9.1 million beneficiaries in 2009), foster
care, care dependency, disability, and old age.9 Other forms of welfare payments include conditional
grants for school feeding and early childhood development, and free health care and nutrition
programs for the poor, and reach about 12 percent of the population.
12.
South Africa’s economic achievements spread well beyond its borders to the rest of SubSaharan Africa. It is by far the largest economy in the region (see Box 2 and Figure 1) accounting for
nearly a third of the SSA’s GDP and two-thirds of Southern Africa’s GDP. Studies have shown that a
one-percent growth of South Africa’s GDP is associated with a 0.4-0.9 percent growth of the GDP of
4
Although researchers mostly agree that poverty did go down in the first half of the 2000s, there is considerable disagreement
over the extent of the decline and to what extent these gains were on account of increased expenditure on social grants.
5
Revenue collection quadrupled and the number of taxpayers more than doubled between 1996 and 2006.
6
These five were the only countries in the 2008 Open Budget Survey that provided “extensive budget information.”
7
South Africa was commended by the report for the independence of its supreme audit institution, and also fared well in
terms of legislative strength.
8
South Africa successfully raised US$2 billion between May and August 2009 and US$1 billion in February 2010 from
global bond markets for 10-yr maturities.
9
Studies have shown the social grant system to be well targeted, with 62 percent of the total going to the poorest 40 percent
of households. By 2005, social grants contributed up to 90 percent of the incomes of individuals in the first two deciles.
4
the rest of SSA, independent of common regional shocks. South Africa’s influence is transmitted via
its dominant stake in the intra-regional trade flows, significant direct investments, and the strong and
growing presence of its banking sector in southern Africa.10 As noted, South Africa also provides
regional leadership at various multilateral fora, including the recent emergence of its influence on
climate change discussions. Its influence is especially felt in the Southern Africa Customs Union
(SACU) countries which, in addition to benefiting from access to its sizable market, also rely heavily
on transfers from South Africa of import tariff revenues. A negative shock in South Africa will
therefore have particularly adverse effects on its neighbors, with the effect being far stronger than that
of a positive shock to growth. South Africa also dominates the regional electricity market through
Eskom, which generates 95 percent of the country’s needs and currently provides a significant share of
the power needs for neighboring Botswana, Lesotho, Namibia, Swaziland, and Zimbabwe.
Box 2: South Africa’s Importance to Regional Growth
Economic conditions in South Africa have important spillover effects on its neighbors, and indeed, on Sub-Saharan Africa
(SSA) as a whole. The channels through which the South African economy contributes to the economic growth of regional
neighbors are varied. The most obvious link is through greater cross-border trade. South Africa is the leading exporter and
importer in intra-regional trade with nearly all countries in the region. Trade with South Africa accounts for around threequarters of the total trade of neighboring Lesotho and Swaziland, and for a quarter to one half of that of the other neighbors,
including Botswana, Malawi, Mozambique, Namibia, Zambia and Zimbabwe.
Investment flows from South Africa to the region are another important channel. Flows to SADC countries have grown in
recent years, from US$1.1 billion in 2001 to US$3 billion in 2006. South African Foreign Direct Investment (FDI) accounts
for a significant share of the total inward FDI stock in a number of its neighbors: Mozambique (27 percent), Malawi (18
percent), Mauritius (17 percent); and Botswana (16 percent). While South African FDI has traditionally flowed to primary
and extractive industries, investments have become increasingly diversified, with a growing focus on services. South Africa’s
investments are also reaching geographically more distant economies, and their impact is enhanced by the fact that South
African-owned firms export more intensively than domestically-owned ones and are more productive (Isik, G. and Y.
Yoshino, 2009).
SOUTH AFRICAN TRADE IN SOUTHERN AFRICA
Country
Exports to RSA
Imports from RSA
(% of total)
(% of total)
Angola
1.5
7.1
DRC
0.4
17.4
Malawi
12.3
35.6
Mauritius
1.7
10.3
Mozambique
14.9
41.9
Tanzania
2.7
12.0
Zambia
21.4
51.5
Zimbabwe
33.4
57.9
2007 data, IMF
There are other channels as well of South African regional
influence. Financial linkages, remittance income (Lesotho
receives the highest share of GDP in remittances, at 28 percent,
mostly originating from South Africa), technological diffusion
through trade or proximity, migration and knowledge flows are
all candidates for causal spillovers. Moreover, because of South
Africa’s size and leadership role in multi-country political and
economic initiatives, developments there are likely to influence
business and consumer confidence and economic sentiment in
other African countries.
While South African growth is highly correlated with regional growth, this relation is likely to be strongly asymmetric (A.
Behar, 2008). Countries which experience negative shocks have particularly adverse effects on their neighbors, with the
effect being far stronger than that of a positive shock to growth. The negative impacts of a sharp reduction in growth, such as
will certainly be experienced if investments in South Africa’s power sector are further delayed, will not be contained within
South Africa, but are likely to generate secondary impacts on neighboring countries. Given growing integration, as evidenced
by larger trade and FDI flows from South Africa reaching more countries and sectors in region, the impact is likely to be very
significant.
10
The Southern Africa Region includes member countries of the Southern Africa Development Community, namely Angola,
Botswana, Democratic Republic of Congo, Lesotho, Madagascar, Malawi, Mauritius, Mozambique, Namibia, Seychelles,
South Africa, Swaziland, Tanzania, Zambia and Zimbabwe. All of these, with the exception of the island countries of
Madagascar, Mauritius and Seychelles, constitute the Southern African Power Pool (SAPP).
5
Figure 1: South Africa, the Economic Powerhouse of Southern Africa
13.
Notwithstanding these achievements, several critical challenges remain. Employment
creation, in particular, has been a major disappointment, preventing more meaningful poverty and
social gains during periods of reasonable growth. The unemployment rate stands at 24 percent—or 31
percent counting the category of “discouraged” workers—which is among the highest in the world.11
The capital and energy intensive nature of industrial production, unequal land distribution, and vast
spatial barriers erected by the so-called “geography of apartheid,” have made progress on job creation
vastly insufficient.12
14.
Human development challenges continue to loom large, with discouraging reversals in
the mortality indicators. The massive increases in social and capital expenditures have clearly
benefited large numbers of previously disadvantaged people. However, the economic and social
impact of these expenditures has not been commensurate. For instance, South Africa's educational
outcomes in terms of reading and mathematics scores are modest compared to, for example, Kenya
and Tanzania. Similarly, the ZAR34 billion (or about US$5 billion) investment in free housing for the
poor has lost a third of its value, because the housing was built in remote and economically
unattractive areas. South Africa continues to battle a dual epidemic of TB and HIV/AIDS, despite
increased allocation of fiscal resources. In 2007, South Africa had among the highest HIV/AIDs
(affecting 18 percent of the population between the ages of 15 and 49 years), TB prevalence rates and
number of TB-related deaths in the world, according to the World Health Organization. Unfortunately,
these developments undid progress on longevity, as life expectancy at birth fell from 62 years in 1995
to just 50 years in 2007.
15.
South Africa is also highly vulnerable to climate change. Its impact on human health,
agricultural production, plant and animal biodiversity, water resources, and rangelands. South Africa
itself contributes over one percent of global CO2 emission, higher than its share of the global
population and economy. This reflects the fact that the emissions intensity (tonnes of CO2 per capita
per annum) is high compared to major developing and developed countries—higher than China and
India, which are also considered coal-based energy economies and Brazil.13
11
Unemployment is concentrated mostly among the youth (with close to 50 percent of the youth labor force currently
unemployed), blacks, and those who are unskilled.
12
The “geography of apartheid” forced black people during the apartheid years to split up between urban townships far from
city centers and the place of work, on the one hand, and barren rural “homelands” with no agricultural potential, on the other.
13
Higher than Brazil only if emissions from land use changes are excluded.
6
The Government’s Response
16.
The Government is fully aware of the criticality of employment creation,14 and
improving the quality of service delivery. Long-term development challenges, especially the
country’s vulnerability to climate change, have also become policy priorities. A relatively fast
recovery from the current economic slowdown, followed by a sustained period of GDP growth in the
range of at least 5 percent (the average rate during 2004-08), is a prerequisite to meaningful progress in
reducing unemployment and continuing social development. For that, quick action on electricity
generation is a “necessary condition,” as starkly demonstrated by the power crisis of 2007/08. The
Government has rightly acknowledged that growth will also need to be much more inclusive, with far
greater emphasis on job creation.15 Accordingly, it has sought to play a more proactive role in
promoting, through tax and other incentives where necessary, more labor-intensive activity in
manufacturing and services, complemented by opportunities for skills development and learning. The
policies and implementation mechanisms that are needed to achieve these “sufficient conditions” for
sustained reduction of poverty and inequality are inherently complex. They are currently being shaped
by a vigorous process of political consensus-building and policy formulation within the government,
and keenly followed by the media, civil society organizations, workers unions, and other stakeholders.
17.
The GoSA has also determined that national sustainable development and global climate
change necessitate South Africa’s transition to a low carbon economy over the long term. It
announced (and reconfirmed in a letter to UNFCC in late January 2010) that it is ready to reduce the
growth in emissions to 34 percent below current expected levels by 2020 and 42 percent by 2025, on
the condition that it is provided with the necessary finance, technology and capacity building and that a
legally binding climate deal is agreed. South Africa has developed and is now beginning to implement
a sophisticated long-term low carbon strategy, which sets credible emissions goals and guides its longterm choices of energy sources to stabilize and then reduce its carbon emission.
Recent Economic Developments: Impact of the Global Economic Crisis
18.
Up until late 2007, the South African economy was doing well. GDP growth exceeded 5
percent for a third year running, bolstered by strong domestic demand, robust construction activity,
and a marked pick-up in services and manufacturing. The widespread power shortages in late
2007/early 2008, together with a slowing global economy and lagged effects of earlier monetary
tightening in an environment of high household indebtedness, had, however, undercut the country’s
growth prospects by the end of 2007. The FY09 budget, presented in February 2008, had reduced the
growth projections from 5 percent in 2007 to 4 percent in 2008 and 2009. Close to one-half percentage
point of that reduction growth could be attributed to electricity shortages, according to a 2009 study by
Deloitte on South Africa’s electricity sector.
19.
The global economic crisis, in particular, has taken a heavy toll on the South African
economy, which is only now beginning to emerge from its first recession in 17 years (See Annex 1
for a more detailed discussion of the recent economic developments). News of GDP growth of 0.9
percent (quarter-on-quarter, seasonally adjusted and annualized) in 2009Q3 came as a welcome respite
following three consecutive quarterly declines during 2008Q4-2009Q2. Growth for 2009 has been
estimated at negative 1.8 percent in the 2010 Budget. The decline in economic activity, albeit
widespread, has been particularly sharp in manufacturing and mining,16 as the demand for the
14
As per the 2009 MTBPS of the Government, “Creating jobs, particularly among millions of relatively unskilled South
Africans, is the country’s greatest economic challenge.”
15
Overall, the current Government has accorded the following areas its highest priority: (i) more inclusive growth, especially
employment creation; (ii) skills development and enhanced quality of education; (iii) improved health care; (iv) rural
development, food security, and land reform; (v) fight against crime; and, (vi) regional cooperation and development. .
16
Manufacturing output fell by 14.5 percent January-October 2009 relative to the same period in 2008, while mining was
down 7.3 percent over this time period.
7
country’s exports plummeted, commodity prices fell sharply17 and domestic private sector demand
came to a virtual standstill. Construction, buoyed by a massive government spending program on
roads, power and stadiums for the 2010 soccer World Cup, has been one of the only sectors to grow.
Reflecting the economic slowdown, the unemployment rate increased from 21.9 percent in 2008Q4 to
24.3 percent in 2009Q4, corresponding to a loss of 870,000 jobs.18
20.
Fortunately, South Africa entered the downturn with a sound macro/fiscal position,
enabling aggressive countercyclical fiscal and monetary responses.19 In particular, fiscal space
generated by several years of budgetary discipline and low public debt, together with South Africa’s
deep and liquid capital markets and continued access to global finance, allowed the Government to
undertake a substantial fiscal expansion to offset the weak private sector demand. The emphasis has
been on significantly scaling up infrastructure spending and protecting and enhancing social sector
spending in certain areas, despite a major decline in revenues. Together with sizeable across-the-board
salary increases in the public sector in 2008/09 and 2009/10, this caused the fiscal balances to worsen
from a surplus of 1.7 percent of GDP in 2007/08 to a deficit of 7.3 percent of GDP in 2009/10: the
ratio of public sector borrowing requirements to GDP in the meanwhile increased from 0.3 percent to
11.8 percent. The 2010/11 budget purports to extend the expenditure trends, by proposing a R846
billion infrastructure investment plan for the FY11-13 period, R454 billion of which would be incurred
by large State Owned Enterprises’ (SOEs) (including R309 billion by Eskom and R49 billion by
Transnet) with substantial cover in the form of government guarantees.20 Fiscal balances are projected
to improve gradually over the medium term, an outcome predicated upon revenues picking up with
economic recovery and moderation of expenditure growth.21 The budget deficit and public sector
borrowing requirement would fall to 6.2 percent and 11.1 percent, respectively, in 2010/11 and further
to 4.1 percent and 7.1 percent, respectively, by 2012/13.
21.
Prompted by the economic slowdown and improving outlook for inflation, South African
Reserve Bank (SARB) has slashed the repurchase rate by 500 basis points since December 2008.
At 7.0 percent, the repo rate is at its lowest since June 2006. CPI inflation has been hovering around
the 6 percent mark since October 2009, when it slipped within SARB’s 3-6 percent target range for the
first time in 30 months, benefiting from a strong Rand and subdued spending by the private sector.
Nonetheless, SARB’s Monetary Policy Committee remains cautious. It has left interest rates
unchanged since August 2009, citing looming electricity tariff increases and double-digit wage
increases earlier in the year as the downside risks.
22.
The strong macroeconomic response by the authorities and the improved global
economic environment has eased the economy out of recession, although the recovery remains
fragile. Growth is projected to improve gradually, from negative 1.8 percent in 2009, to 2.3 percent in
2010 and further to 3.6 percent by 2012. Economic recovery remains tentative and uneven, however,
particularly on account of continued weakness in domestic private sector demand.22 Private credit fell
for the first time in over 40 years in October of 2009 as households continued to deleverage under the
burden of high indebtedness despite lower interest rates. It is especially worrying that private sector
17
Despite strong recovery in the past few months, most commodity prices remain below their pre-crisis levels.
A broader definition of unemployment, including discouraged workers, saw an increase from 26.7 percent in 2008Q4 to
31.1 percent in 2009Q3.
19
The framework for South Africa’s response to the crisis was discussed and agreed upon by Government, labor, and
business, and community representatives in February 2009. Key elements of the agreed framework included fiscal and
monetary expansion, accelerated public sector investment, protection of jobs and investment in people and productive
capacity, and supporting vulnerable sectors such as clothing and textiles and automobile manufacturing.
20
Other areas of emphasis in the budget include employment programs, social security benefits, health, education, fighting
crime, and rural development.
21
Public expenditure is projected to grow at around 2 percent per year over the FY11-13 period, compared with 7.2 percent
growth during FY06-09.
22
Household spending fell for the 5th consecutive quarter in 2009Q3, reaching 61 percent of GDP, the lowest since 1994Q1.
18
8
confidence in economic recovery is still to develop, causing it to shy away from fixed investment.23 In
addition, mining exports have weakened despite record gold prices and strong recovery in platinum, on
account of structural issues at mines and a strong Rand.
23.
South Africa’s external and financial sectors remain robust despite the global crisis.
After an initial dip, foreign portfolio investment has recovered strongly, comfortably covering South
Africa’s large current account deficit (7.1 percent of GDP in 2008 and 4.3 percent of GDP in 2009).
Foreigners net purchased over US$10 billion worth of equity on the Johannesburg Stock Exchange in
2009, exceeding the net outflow of about US$6.3 billion in 2008. In addition, a slump in imports and a
mild recovery in exports have ended a prolonged period of trade deficit, taking considerable pressure
off the current account. These developments on the BOP have led to a full recovery in the value of the
Rand against the major currencies: the Rand/US$ rate and the nominal effective exchange rate stand
firmer today than at end August 2008, just before the onset of the global crisis.24 FDI has also been
strong, with net inflow of $3.7 billion in the first three quarters of 2009, reflecting in large part
investments in telecommunications. Gross external debt stood at a comfortable 26 percent of GDP in
September 2009 and less than 100 percent of exports of goods and services.25 Leaning against the
wind to prevent excessive appreciation, SARB accumulated international reserves, taking gross
reserves from $34.1 billion at end-2008 to $39.5 billion at end-January 2010.
24.
South African banks remain in a sound position, benefiting from limited exposure to
foreign currency debt and more disciplined lending practices ensured by the National Credit Act
of 2007. According to a recent SARB Supervision Report, local banks’ capital-adequacy ratio
increased from 11.8 percent to 13 percent over 2008 and liquid assets held by banks exceeded statutory
requirements throughout 2008. Implementation of the Basel II process has been of high quality. The
ratio of non-performing loans (NPLs) to loan advances increased from 2.8 percent in July 2008 to 5.5
percent in August 2009 as a result of the crisis, but remains manageable.
The Electricity Sector in South Africa’s Development Strategy
25.
The GoSA’s mass electrification program has been a success as a means of meetings
citizens’ basic needs. The program started in 1994 with electrification levels of 34 percent, and
reached an 81 percent level of electrification by 2007. This large scale electrification took place
without any significant additions of new generation capacity. In 2003, the GoSA launched the Free
Basic Electricity (FBE) policy, which envisaged provision of a minimum of 50 kWh of free electricity
per month to the poor. At present, the FBE covers approximately 3 million households; 1.2 million of
whom are customers of Eskom (mostly in rural areas) with the remainder served through municipal
distribution companies. In addition, there is a lifeline tariff based on cross-subsidies for consumers
utilizing less than 350 kWh per month.
26.
Availability of affordable and reliable power supply has been essential to propelling
South Africa’s economy.26 As shown in Figure 2, electricity consumption increased by 60 percent
between 1994 and 2006, responding to the demands of the mass electrification program, a 50 percent
cumulative increase in real GDP, and rapid urbanization.27 Residential consumption of electricity,
one-fifth of total consumption, grew by 50 percent, as access to electricity multiplied and rising
23
Gross fixed capital formation by private sector fell by 14.1 percent in 2009Q3, following declines of 16.8 percent and 9.4
percent, respectively, in Q1 and Q2 of 2009, as firms feverishly ran down inventories rather than invest in production
expansion to meet demand; in an apparent lack of confidence in the durability of the recovery.
24
Among the emerging markets, in 2009 the Rand’s recovery against the US$ was second only to the Brazilian Real’s.
25
The Institute of International Finance, January 22, 2010, “South Africa: Looking Beyond the World Cup.”
26
The energy sector, electricity in particular, plays a critical role in the South African economy. The sector directly accounts
for 15 percent of the country’s GDP and employs close to 250,000 people.
27
The urbanization rate in South Africa increased from 50 to 62 percent in the last decade.
9
income levels and urbanization saw greater use of electricity in people’s lives. Industrial consumption
which accounts for 60 percent of total power usage, rose by 55 percent over this period.
Figure 2: Power Supply and Gross Domestic Product28
27.
Demand pressures arising from increased access and economic growth have been
especially severe for South Africa. GDP per unit of electricity consumed in South Africa in 2006
was only 60 percent that of the average UMIC, 40 percent of Brazil and 30 percent of Mexico; in fact,
it was at par with the average low-income country. The capital- and energy-intensive nature of the
economy stems from both rapid urbanization and electrification, and a mechanized manufacturing
sector that requires heavy use of electric power. Mining, another energy intensive activity, also plays
an important role.29 South Africa is a globally leading producer of gold and platinum, and the
production cycles (extraction, processing, and supply) of both are highly energy-intensive. Even in a
slow GDP growth scenario, electricity demand is expected to exceed supply around 2013 (without the
proposed project); thereafter a shortage of electricity will negatively impact on households, the
provision of basic services, small business and industry, manufacturing and mining activities in the
country.
Figure 3: GDP per unit of energy use (constant 2005 PPP $ per kg of oil equivalent)
28
In the first figure, the left y axis represents the GDP and the right y axis represents the power consumption in ‘000 GWh.
Mining constitutes only 7 percent of GDP, but plays a much more significant role through its contribution of intermediate
goods for the next stage of production.
29
10
28.
The strong growth in electricity demand unfortunately was not matched on the supply
side. No significant new generation capacity came on-stream in the new millennium. The private
sector showed little interest to invest for a variety of reasons,30 namely: (i) slow structural reforms in
the electricity sector and hesitant progress towards market-based supply in light of the California
Electricity Crisis of 2000 and other similar failures of competitive market-based reforms in developing
countries; (ii) withdrawal from international markets by traditional power sector investors during the
post-Enron bankruptcy period in 2001; (iii) low electricity prices prevailing in South Africa adversely
impacting financial viability of new investment; and (iv) the GoSA’s incomplete policy compendium,
which made large-scale investing in the power sector more risky and generally unattractive. Hence, not
surprisingly, peak demand caught up rapidly with the country’s generation capacity, which caused
Eskom’s reserve margins to fall to dangerously low levels by the end of 2007.31 Whereas the
appropriate level of reserve margin for South Africa is considered to be around 15 percent by Eskom,
it was down to 6 percent by early 2008.
29.
By the end of 2007 generation capacity fell far short of peak demand. This led to
immediate load-shedding by Eskom to prevent the system from complete collapse, which continued
until early February 2008.32 As discussed earlier, the impact of the power crisis on the country's
economy was serious and immediate. GDP growth fell to 1.7 percent (quarter on quarter, seasonally
adjusted and annualized) in the first quarter of 2008, its lowest level in more than six years. Mining
fell 26 percent, its sharpest decline on record, as key mining operations were shut down for two weeks,
and manufacturing fell by 0.6 percent (see Figure 4).33 A study by Deloitte found that a permanent
drop of 10 percent in electricity supply would have reduced GDP by 0.6 percent in 2008 and by 1.2
percent in 2009.34 (see Figure 4 below).
Figure 4: Change in Electricity Reserve Margins & Impact on GDP & Manufacturing
30
Electricity investment with private participation equaled US$1.3 billion in South Africa over 1995-2007; in comparison,
Mexico invested US$10 billion and Brazil US$70 billion with private participation.
31
This level is similar to the reserve margins California experienced during its emergency period that caused rolling
blackouts and threatened the stability of the grid. With such low reserve margins, and fearing a nation-wide blackout, Eskom
was forced to postpone taking plants out of service for regular maintenance. Deferral of asset maintenance exacerbated the
energy shortages by increasing equipment failures and decreasing overall plant reliability.
32
Eskom implemented a number of measures during the crisis to lower overall demand by a target level of 3,000 MW.
Actions included: (i) power rationing (as a first line of defense) and associated penalties for exceeding rationed amounts; (ii)
a program of energy efficiency measures; and (iii) customer awareness campaigns. Voluntary measures to encourage use of
alternate sources of energy are also being deployed. Eskom has plans to subsidize households that install solar energy heating
systems.
33
Mining production in 2008Q1 was also negatively affected by industrial action and unscheduled mine closures due to
safety concerns. In addition, rising input prices and higher interest rates also served to dampen growth.
34
Eventually, according to the study, the growth impact would subside as the economy moves to more efficient and less
energy-intensive production patterns.
11
30.
Electricity shortfalls in South Africa also hurt the economic development of the region,
which depends on South Africa for its electricity. A number of Southern African countries, such as
Botswana, Namibia, and Zimbabwe, have long relied on Eskom-generated electricity supplies from
South Africa. About 70 percent of Botswana’s power requirements were met through imports from
Eskom in 2008. South Africa’s energy crisis has resulted in energy shortfalls in these countries; for
example has started regular load shedding, which will worsen as deficits grow until it’s domestic
capacity comes online. Less reliable electricity is also expected to lead industries and small and
medium enterprises (SMEs) to invest in self-generation, which will reduce competitiveness by
increasing production costs.
The Government’s Power Sector Development Strategy
31.
Universal electrification, backed by affordable and reliable power supply is the
cornerstone of the Government’s sector development strategy. The electricity crisis halted the
good progress achieved on universal electrification and results slowed in 2007/08 as a result of crisis.
The program has been set back by at least a year from the target 100 percent achievement planned for
2013. The crisis reinforced the need to urgently implement Eskom’s medium-term investment
program. It became apparent that the economic and social cost of inadequate electricity supply was
unacceptably high. Moreover, a government faced with spending pressures related to job creation,
social protection, service delivery improvement, and infrastructure development could ill-afford to risk
losing fiscal revenues resulting from a slowdown in growth.
32.
The Government has responded with an approach to energy security which is
underpinned by the long-term need for low carbon growth. The approach includes: (a)
accelerating improvements in energy efficiency, investing in clean energy, and pursuing regulatory and
economic instruments to stabilize greenhouse gas emissions over the medium term and to reduce them
over the long term, as envisaged in the GoSA’s low-carbon strategy; and (b) assigning priority in the
near term to increasing generation capacity and reliability of electricity.
33.
The GoSA’s near-term crisis response primarily focuses on four areas: (i) accelerating an
energy efficiency program which targets low-cost high-impact interventions including solar water
heaters, compact fluorescent lamps (CFLs) and demand side management options, such as ripple
control of appliances; (ii) increasing generation capacity by adding new short-term, high-cost capacity,
re-commissioning old plants that have been taken out of service and financing Eskom’s aggressive
“New Build” program entailing significant addition to generation capacity; (iii) improving Eskom’s
operating practices to increase supply-side reliability; and (iv) designing a legal and regulatory
framework to attract private sector investment in generation, with a focus on renewable activities.
34.
For the longer term, GoSA’s policy response accounts for coal being dominant in the
generation mix.35 Coal is abundantly available to South Africa for large-scale power generation,
especially considering the country’s need to add over 12,000 MW over the next 5-7 years. South
Africa is the world’s fifth largest producer of coal with recoverable reserves of 49 billion tons, the
sixth largest in the world. The costs generally associated with extraction of this high-quality and
reasonably low-sulfur content coals are modest. The country has insignificant deposits of oil or
natural gas. The greatest potential for large renewable projects is limited to CSP and to a lesser extent
wind; new hydropower potential is largely non-existent. CSP has the potential for substantial scalingup, and matches most closely with the need for baseload power. However, the technology has not yet
reached the gigawatt scale (to meet the large baseload capacity requirements of South Africa), and is
currently costly, with significant risks for a country facing a demand-supply imbalance and the
35
About 87 percent of all electricity generated in South Africa comes from coal-fired power plants. The remainder of
generation comes from hydropower plants (including pumped storage, using unused coal capacity during off-peak times),
liquid-fueled plants and one nuclear plant.
12
incremental costs of meeting the new generation needs, estimated at billions of dollars. Wind energy is
a commercially mature renewable energy technology, but remains underexploited in South Africa and
because it is intermittent, is not well-suited to meet baseload requirements. Current estimates of wind
power potential are in the range of 4,000 MW along the East and West coasts of South Africa.
35.
There are no feasible near-term regional renewable alternatives to meet the demand in
South Africa. There is a severe shortage of generation capacity in the sub-region. South Africa is part
of Southern African Power Pool (SAPP), which includes twelve countries of the sub-region, nine of
which are interconnected. All twelve countries in SAPP have been experiencing energy shortages,
some more than the others, with shortages in South Africa being a primary cause. The main reasons for
the shortages are:
 South Africa dominates the SAPP, accounting for nearly 78 percent of the capacity and
about 85 percent of energy generation and is a net exporter to 6 countries. South Africa’s
troubles with adequate power generation will quickly spread and affect the SAPP
countries.
 Demand far exceeds available capacity. New capacities were not added in the last decade
while the demand grew, straining the older units whose reliability decreased at the same
time. The growing demand exceeded available capacity and eroded the reserve margins .
South Africa’s crisis - a shortfall of about 7,000 MW (or 20 percent of peak demand)
forced load shedding, blackouts, and curtailed exports. Therefore, Eskom is unlikely to
maintain exports to SAPP countries over the medium-term.
 The rest of SAPP is too small to handle the solutions alone. The available capacity in the
rest of SAPP (about 9,000 MW) is not sufficient to cover short-falls and the transmission
system and links are not adequate or flexible to handle shifts of large amounts and
directions of power flows. More than 95 percent of the energy in the SAPP network is
consumed within the producing countries and the trade / exports are relatively small.
South Africa’s energy crisis caused ripple effects in the SAPP, especially in Botswana and
Namibia.
36.
The demand forecasts for the SAPP countries (2008-25) indicate growth at an average annual
rate of about 2.9 percent, which is similar to the historical rate of about 2.8 percent growth during
(1998-2006). The SAPP system optimization plan prepared by SAPP consultants (Nexant, USA)
indicates that about 39,000 MW of additional capacities are needed across SAPP through 2025, of
which 22,000 MW (or 56 percent) would be needed in South Africa alone. A part of these new
additions will replace about 12,000 MW of old units, especially coal power plants. The specific
projects were selected through an optimization model which considered 93 power plant candidates by
the SAPP utilities, as well as about 90 transmission links and interconnections associated with specific
generation projects. Of the 39,000 MW new additions through 2025, 11,000 MW would be hydro and
28,000 MW thermal (or nuclear), requiring 11 new transmission interconnections.
Table 2: Planned SAPP Base Case Capacity Expansion Plans up to 202536
SAPP
to 2015
2016-2025
South Africa
to 2015
2016-2025
Hydro (MW)
Other* (MW)
Total (MW)
11,000
6,000
5,000
3,300
2,300
1,000
28,000
15,500
12,500
18,800
9,200
9,600
39,000
21,500
17,500
22,100
11,500
10,600
(* includes renewable – solar, wind, nuclear; thermal - gas, diesel, coal)
36
This table only presents the new capacity additions that have reached commissioning. It excludes the CSP and wind project
to be considered under the proposed project.
13
37.
The SAPP expansion plan contemplates expanding hydropower capacity from 21 percent now
to 26 percent by 2025, and reducing coal power plants from 73 percent now to 67 percent by 2025 (see
charts below). While coal-based power continues to be significant due to the region’s abundant
reserves, the contemplated expansion plan reduces SAPP’s CO2 intensity through a gradual reduction.
This is achieved by a combination of increased share of hydropower plants and improved efficiency of
coal power plants through infusion of new and better technologies.
38.
An alternative scenario shows that hydropower may be increased to 16,500 MW by 2025 with
a corresponding further reduction in thermal capacity. However, this scenario involves higher risks and
uncertainties:
(i)
The investments in coal power plants in South Africa and Botswana of about 8,500 MW
combined post-2020, are shifted to non-investment grade countries (DRC, Malawi,
Mozambique, Zimbabwe) raising financing risks and uncertainties. It is also predicated on
Eskom providing PPA guarantees to these projects.
(ii)
The plan requires about 50 more transmission interconnections, including the long
transmission line from DRC to South Africa to support the 4,300 MW Inga 3 project.
Since transmission lines are associated investments to power plants, this assumes the same
risks as those of power plants for financing and timeliness.
Figure 5: SAPP Capacity Mix 2008-2025
39.
While pre-2020 generation investments are likely to be along the base case scenario, it is
possible to shift the post-2020 investments to align with alternative case scenario with more hydro and
hence further lower CO2 intensity of SAPP. The picture in 2025 therefore could look different with
larger share of hydro in the mix. The SAPP region has one of the largest hydropower potential in the
continent in DRC (estimated at 40,000 MW). The region also has solar energy potential. South Africa
has the fifth largest reserves of world’s uranium. Gas reserves are limited, but at the same Botswana
has large estimated reserves of CBM (about 190 TCF). Therefore, it is expected that the share of fossil
fuels in the energy mix would decline over time in preference for renewable energy. As this project
demonstrates, South Africa has started on the lower carbon path. Measures like feed-in tariffs to
promote renewable energy from wind and solar, development of regional hydro, exploring nuclear
power and coal-bed methane would contribute to long term CO2 reductions.
40.
The GoSA realizes that continued reliance only on coal-based energy is not a long-term
option. In a significant move, the Long Term Mitigation Scenarios (LTMS) endorsed by the Cabinet
envisage a shift away from coal toward renewable energy and nuclear, with a view to ensuring that the
carbon emissions from all sources, including electricity generation, peak during 2020-2025, plateau for
a decade, and then begin declining thereafter. The LTMS, one of the first in the developing world, has
been a pioneering effort that combines high-quality research-based scenarios with extensive
stakeholder consultation. It recommends five priority climate change mitigation options in industrial
energy efficiency, renewable energy, nuclear, passenger modal shift, and improved vehicle efficiency.
14
Box 3: South Africa’s Long Term Mitigation Scenarios
The scenarios are based on Marginal Abatement Curves built up from specific projects and programs to reduce GHGs.
Energy Efficiency and Demand Side Management Programs are the first steps towards implementing the low carbon strategy.
Recognizing the global challenge from climate change impacts, the Government prepared five scenarios designed to decrease
GHG emissions.
• a “Growth Without Constraints” scenario, with no GHG constraints, so as to set a baseline representing outcomes from
unrestricted emissions (“business as usual” scenario);
• a “Required by Science” scenario, to help the world fully meet the global warming challenges by decreasing GHG
emissions in the 60-80 percent range. This scenario assumes that there are no resource constraints and thus establishes what is
considered to be the lower bound GHG emission trajectory; [endorsed by Cabinet in July 2008]
• a “Start Now” development trajectory, in which the public sector invests in alternatives that have important co-benefits,
such as EE/DSM, renewable energy and nuclear power;
• a “Scale-up” scenario, which builds on the “Start Now” scenario through regulatory interventions, extending EE/DSM,
renewable energy, and nuclear power interventions into more costly options; and
• a “Use the Market” scenario, which is designed to implement a radical shift in lowering carbon emissions, by implementing
a carbon tax.
The detailed implementation plan would, among others, include energy efficiency, more efficient fossil-fueled power plants,
electricity demand side management and renewable energy. The GoSA has also established a Designated National Authority
(DNA) to support projects under the Clean Development Mechanism (CDM) of the United Nations Kyoto Protocol. The
DNA has to date approved 19 projects ranging from energy efficiency and small hydro projects to cogeneration from the
sugar and ferrochrome industries.
41.
The LTMS is the basis of the GoSA’s mitigation strategy. This includes: (a) implementing
the “Start Now” strategic option focusing on accelerated energy efficiency and conservation across all
sectors, especially industrial, commercial, transport and residential; (b) investing in credible carbonfriendly technology research and development, new clean energy resources, and behavioral change;
and (c) pursuing regulatory mechanisms contained in the “Scale-Up” scenario together with economic
instruments from the “Use the Market” scenario (e.g., taxes and incentives).
42.
A number of other recent national and international commitments have further signaled
the GoSA’s fortitude to pursue a low carbon growth path. The major actions include:
(a) Ratification of the United Nations Framework Convention on Climate Change (UNFCCC)
in August 1997 and accession to the Kyoto Protocol in July 2002.
(b) Adoption of a National Climate Change Response Strategy (2004), which outlined a broad
range of principles and policy measures of mitigation and adaptation to climate change.
(c) Association with the Copenhagen Accord (2009), which has committed South Africa to
implement economy-wide emissions targets for 2020 and 2025, on the condition that it is
provided with the necessary finance, technology and capacity building and that a legally
binding climate deal is agreed.
(d) Issuance of the Electricity Regulations for Energy Efficiency.
(e) Adoption of a National Energy Efficiency Strategy (2006), which set an ambitious national
target for energy efficiency improvements of 12 percent by 2015. In April 2006, a
National Energy Efficiency Agency (NEEA) was established with the mandate to promote
energy conservation.
(f) Adoption of a 2005 White Paper on Renewable Energy, and setting a target to supply four
percent of electricity demand from renewable sources by 2013 (about 2,000 MW).
43.
Implementation of actions for development of renewable energy has already begun. The
following measures illustrate the GoSA’s commitment in supporting the global goal of reducing GHG
emissions:
15
(a) The GoSA has adopted attractive and private sector-friendly feed-in tariffs37 and
established a suitable legal and regulatory framework to incentivize private participation in
development and enhanced use of renewable energy;
(b) South Africa has begun implementation of its climate change strategy based on agreed
principles of accelerated energy efficiency and conservation across all economic sectors,
inter alia through more stringent building standards;
(c) Ambitious research and development targets for carbon-friendly technologies will be put
in place and be supported by new resources;
(d) Targets will be set for electricity generated from both renewable and nuclear energy
sources by the end of the next two decades; and
(e) Regulatory mechanisms will be combined with economic instruments such as taxes and
incentives with a view to further developing energy efficiency policies, an escalating CO2
tax, and diversifying the energy mix away from coal whilst shifting to cleaner coal, by for
example introducing more stringent thermal efficiency and emissions standards for coalfired power stations.
Concrete Measures by Eskom and the GoSA to responsibly close the demand-supply gap and
implement LTMS options
44.
The GoSA has adopted a proactive policy approach to close the supply-demand
imbalances in a responsible manner. A string of policy actions in recent months adequately
demonstrate the Government’s commitment to addressing the sector’s supply woes in a socially and
environmentally responsible manner. Major actions include:
(a) Ensuring financial viability of the electricity sector, most notably through the issuance of
the Electricity Pricing Policy (EPP) in December 2008, which directs the National Energy
Regulator of South Africa (NERSA) to ensure a tariff trajectory leading to full cost
recovery, to put Eskom back on a path of financial sustainability within five years. The
Electricity Regulation on New Generation Capacity, which envisages a greater role for the
private sector, was approved in August 2009.
(b) Improving domestic and regional electricity supply security through enactment of the
National Energy Act in 2008; issuance of the Electricity Regulation on Integrated
Resource Planning (late 2009); issuance of the Electricity Regulation on IPP Cost
Recovery (late 2009); and issuance of the Electricity Regulation on Energy Efficiency
(late 2009). These would help ensure a safe generation reserve margin, generate private
sector interest in bidding for power generation capacity, and lock-in off-take electricity
purchase agreements with power producers in neighboring countries.
(c) Supporting the poor by implementing the relevant provisions of the EPP. The EPP
establishes the principles for electricity pricing levels, including provision of support for
the poor, the process for establishing prices and the responsibilities of the regulator for the
issue of rules needed to implement the pricing principles. In order to protect the poor from
the impact of tariff increases, free basic electricity is currently provided to 27 percent of
the poorest connected consumers. Tariff structures also allow subsidized electricity for up
to 350 kWh per month for the next block of consumption.
37
The feed-in tariff system obligates Eskom to buy renewable energy at above-market rates set by the Government to
compensate for the cost disadvantages of renewable energy sources.
16
(d) Promoting energy efficiency. The Government’s Integrated Resource Plan emphasizes
moderating the growth in demand through various energy efficiency measures. This has
resulted in reducing the demand forecast by nearly 3,000 MW over the first 5 years, as
well as significant GHG emissions savings.
(e) Restructuring of the energy sector to increase operational efficiency and enhance private
sector participation. At the apex level, DoE has undertaken the development of an
Integrated Resource Plan (IRP), which will provide the overarching framework for
electricity sector development. In parallel, the Government is taking steps to create a
single buyer and an independent system operator (to be established as Eskom’s
subsidiaries in the initial phase). The GoSA plans to take the legislative action that will
allow these Eskom subsidiaries to be divested as a separate entity.
45.
Eskom plans to double its generation capacity to 80,000 MW by 2025, while also
reducing the proportion of electricity generated from coal to approximately 70 percent from
current levels of about 90 percent. In order to replace coal with a cleaner fuel source, the GoSA is
exploring options to increase nuclear capacity by 20,000 MW and taking steps to add 1,700 MW38
from renewable supply sources, namely solar and wind power with the purpose of priming the market
so that private-led renewables investments can follow. Eskom expects to devote a significant portion
of its capital expansion program budget to the diversification of its sources of energy generation,
especially increased renewable energy sources. This program of increasing capacity based on coal,
renewables and nuclear is consistent with the GoSA’s low carbon strategy.
46.
In response to the exigent situation, Eskom has embarked upon a New Build and Major
Maintenance Program. This program entails an investment commitment of US$50 billion over a
short 5-year period.39 This is part of its immediate plans to add new generation capacity of up to
20,000 MW over the next 5-7 years, primarily based on domestic sources.40 The GoSA and Eskom
have agreed to focus on adding new capacity, based on supercritical technology to minimize carbon
emissions, and on improving efficiency of its coal-fired power plants. The proposed technologies are
consistent with the LTMS’s emphasis on shifting to higher efficiencies in power supply and carbon
capture and storage in coal-fired power plants. Accordingly, Eskom included in its large-scale
investment program two coal-fired supercritical plants each with 4,800 MW generation capacities, and
a Pumped Hydropower (Ingula) scheme, which would add another 1,300 MW. This would be
supplemented with about 750 MW from hydro-based imports, and about 700 MW from renewable
energy-based IPPs.
47.
The investment program proposes to accelerate new renewable technologies. Options
available to the Government, at this time are limited to CSP and wind.41 Studies are underway for 500
MW in the Western and Eastern Cape Provinces and current estimates of wind power potential are
about 4000 MW along the East and West coasts of South Africa. CSP potential is estimated to be 3038 GW in South Africa. Both CSP and wind technologies are expected to make a significant
contribution to the Government’s target of 10,000 GWh (about 1,700 MW equivalent) from renewable
energy sources by 2013. In addition, the Eskom investment program includes energy efficiency
investments; Eskom has been taking discrete steps to increase supply and demand side management.
38
The GoSA is currently assessing the feasibility of a more ambitious RE target.
Beginning CY 2008; at an exchange rate of US$1=Rand 8.
40
This massive expansion plan is larger than the combined undeveloped generation potential of Mozambique and Zambia,
two countries that have the most feasible sources of regional supply in the medium-term, and much larger than all generation
projects that have been deemed feasible in the sub-region.
41
Of the renewable energy options, CSP is the most expensive but offers the greatest potential for baseload power (unlike
wind power and solar photo voltaic power) and has a scale-up potential in South Africa. However, at present the technology
does not allow large-scale developments. Wind energy is a commercially mature renewable energy technology, but despite a
high growth rate of wind farms in the global market, its development in South Africa has been minimal to date.
39
17
Nearly 675 MWs of DSM savings were achieved by 2008 and the target is to achieve 3,000 MW of
such savings by 2013. Going forward, these measures will be complemented by a major effort
supported by the private sector especially in areas such as expanded use of solar water heaters.
Additional measures also include supply side efficiency improvement investments for upgrading the
efficiency of an agreed list of old power plants and shifting from roads to railways for coal
transportation. All these measures are expected to provide significant reduction in carbon emissions
arising out of the energy sector.
48.
Eskom’s 100 MW solar project represents a significant effort on the global scale of
today’s nascent solar industry. The world's largest concentrating solar plant, capable of supporting
base load supply is located near Seville, Spain, with a capacity of 20MW. The plant became
operational in May 2009. In September 2009, the Chinese government announced its intention to
construct a 2GW solar power plant in Ordos City, Inner Mongolia, which will be constructed over a
nine-year period. However, the first phase of this project will only be a 30MW demonstration project.
Besides limited maturity in technology and scale, developing and financing such projects is also a
challenge. US$1.4 billion in loan guarantees for Bright Source Energy’s construction of three
concentrated solar plants in the Mojave Desert in California, USA were provided to the project. These
plants are expected to generate 400MW of electricity and are the world’s largest concentrating solar
project to have passed the development stage. At the present time, therefore, it is simply not feasible
to consider concentrated solar as a viable alternative to coal-fired baseload power in view of both
technology and costs.
49.
With respect to wind, South Africa’s intends to attract private sector investment into this
more mature renewable technology. Hence, the proposed 100MW wind power project is considered
as a demonstration and facilitation project. It will capture lessons and make these available as public
goods and build up supportive infrastructure and systems integration elements such as transmission
infrastructure for future wind capacity expansion. Because the Government is on track to establish an
independent system operator to purchase power from private sector companies (using feed-in tariffs),
investing more public financing into additional wind power projects is not optimal.
50.
Supercritical and Carbon Capture and Sequestration (CCS) space-ready coal-fired
projects constitute the best feasible domestic generation potential that could be brought on line
in South Africa to cover the supply-demand gap over the coming 5-year period. The Medupi
power plant has been developed by Eskom using the best proven technology to minimize carbon
emissions. The power plant will be the first in Africa to use the more-efficient “supercritical”
technology. In addition to using the supercritical design, the power station will be the largest drycooled power station in the world, reflecting the concerns over water scarcity in South Africa.
51.
The GoSA and Eskom have begun the development of South Africa’s first commercial
utility-scale renewable energy projects. South Africa’s CTF Investment Plan, which supported
implementation of the mitigation priorities and strategies and was endorsed by the CTF Trust Fund
Committee in October 2009, consists of a US$2.35 billion program to scale up CSP and wind
(including transmission infrastructure to support private sector developers), support for development
of a private sector-led solar water heater market and energy efficiency investments. A second phase of
the Investment Plan will focus on sustainable transport options, including modal shifts to public
transport. As a follow-up to this IBRD loan, South Africa will approach the CTF to request financing
for the solar and wind energy renewable components that are part of the CTF approved Investment
Plan.
18
Box 4: South Africa: Leading the Implementation of Clean and Efficient Coal Technologies in Africa
South Africa has undertaken to use the most efficient technologies available in the development of all of its new coal-fired
power plants. This is in line with the GoSA’s commitment on climate change. Adoption of these technologies also is in line
with the World Bank Group’s Climate Change Strategy.
Eskom’s New Build Program consists of two power plants designed to operate under supercritical steam conditions to
maximize plant efficiency and thereby minimize GHG emissions. These plants will be equipped with Flue Gas
Desulfurization (FGD) to control sulfur emissions. Since coal is bound to remain the primary source of energy for some time
to come, Eskom and the GoSA are exploring designing all future (after Medupi) coal-fuelled power plants for CCS readiness.
South Africa has also joined the Carbon Sequestration Leadership Forum and is actively investigating Carbon Capture and
Sequestration (CCS) as one of the potential tools to limit greenhouse gas emissions. South Africa has already investigated
potential carbon sources and storage sites. The Government has embarked on a survey of the geological make-up of the
country to determine suitable areas for carbon storage. In addition, a separate GoSA assessment shows that carbon dioxide
emissions were concentrated in the central industrial region, the highest emission concentrations being associated with coalfired electricity generation and synthetic liquid fuel plants. Quantifying the emissions indicated that approximately 39 percent
of emissions were non-sequestratable because of their diffused nature. Of the sequestratable emissions, approximately 65
percent were identified to be associated with electricity generation. For its part, Eskom’s future power station design allows
for sufficient space for carbon capture in all its new power stations.
South Africa is currently taking steps to facilitate implementation of CCS projects. These include identification and
characterization of storage sites, development of national regulations that would guide CCS activities in South Africa, and
adoption of international regulations that would allow the use of carbon credits. The CCS targets are first test injection in
2016 and first full operation in 2020.
Eskom’s first underground coal gasification (UCG) pilot plant has been operating for nearly two years. Though modest in
size (production 13 million cubic metres and 100kW of power capacity), its success has accelerated efforts to scale up.
Following satisfactory assessment of the plant’s performance and environmental impacts, Eskom through its own resources,
is executing a larger project 40-times the scale of the pilot. Eskom’s goal is to develop a new 350MW UCG-integrated
gasification combined-cycle (IGCC) ultra-high-efficiency power station over the next few years. This could be a candidate
project for the next round of climate funding.
52.
Complementary to CTF financing that South Africa will pursue, there are programmatic
opportunities to benefit from the carbon market for low carbon initiatives. The World Bank’s
Carbon Partnership Facility (CPF) offers an opportunity for South Africa to attract carbon finance
resources for a period of up to ten years (beyond expiration of Kyoto protocol in 2012) to support
programmatic and sector-based efforts to reduce emissions over the medium term, e.g., energy
efficiency, solar water heating, and renewable energy. Participation in the CPF will allow South Africa
to establish and monetize its climate mitigation assets in anticipation of the creation of any post-2012
global carbon markets.
53.
The GoSA’s strategy to move to a low carbon energy sector will be primarily led by the
private sector. Eskom with the proposed renewable projects will play a catalyzing role in the initial
years, while the GoSA creates an enabling environment that encourages private investment. As
mentioned, the GoSA has already adopted attractive and private sector-friendly feed-in tariffs for
renewable technologies, including wind and CSP. In addition, the private sector, along with
commercial financiers, is expected to finance the energy efficiency program related to solar water
heaters. The Government and Eskom are also accelerating research and development of coal bed
methane and underground coal gasification potential.
Eskom’s Financial Situation
54.
The financial commitment of the New Build and Major Maintenance Program – about
US$50 billion over a 5-year period – places tremendous strain on Eskom’s finances.42 Current
electricity prices in South Africa are unsustainably low. For the last several years, bulk electricity
tariffs were based on Eskom’s low depreciated asset base, valued at historical net book values and
little to no requirements for investment capital. During the 1980s and 1990s, Eskom’s tariff thus
42
At an exchange rate of US$1=R8.
19
steadily reduced in real terms, which means that electricity prices in South Africa are now far lower
than in any other comparable countries and well below full “current” economic cost. The cost of
building a new fossil fuel power station is six to seven times that of the average cost of the existing
power station per megawatt of capacity. The South African economy is growing, resulting in the need
for significant investments in electricity infrastructure to meet continued growth in demand. The
GoSA is cognizant of the fact that the cost of this new capacity (developed either by the public or the
private sector) will have to be reflected in the future pricing of electricity and to this extent it approved
the EPP in December 2008 to ensure full cost recovery tariffs over a period of 5 years.
55.
Despite a cumulative 68 percent increase in tariffs since mid-2008, current average retail
electricity tariffs, at about 5 US cents/kWh, are below Long Run Marginal Costs (LRMC). These
tariffs allow Eskom to meet its operating-costs, but would provide only a small portion of its near-term
investment finance requirements.43 Even though there have been delays in the implementation of
sector reforms, especially those targeted at full cost recovery through tariffs over the medium term,
significant new policy changes have been put in place by DoE such as the Energy Pricing Policy (EPP)
and the new regulations providing the enabling framework for private investment in power generation.
To date, the regulator has approved three tariff increases, thereby moving the tariff trajectory towards
full price recovery. To protect the poor, NERSA has limited the increase to the poor to about 15
percent, thus resulting in a higher average increase to other customers. Based on the principles
approved under the 2008 EPP and Eskom’s Multi-Year Price Determination (MYPD2) application to
NERSA in November 2009, on February 24, 2010, NERSA has announced its decision to allow
Eskom to raise tariffs by 24.8% in FY 2011, 25.8% in FY 2012 and 25.9% in FY 2013. The decision
will allow the average selling price of electricity sold by Eskom to increase by 98% in three years and
reach 10 US cents/kWh by 2014.
56.
The GoSA, Eskom and NERSA realize that high tariffs could impact the economy.
Therefore, NERSA decision followed an extensive consultation process provided for in the legislation,
the outcome of which is appropriately reflected in the final decision on the Eskom tariff increase
application. Over the years, NERSA has followed sound regulatory principles and engages external
expertise as required, using its own resources. The track record of NERSA in approving Eskom’s
tariff applications over the last two years provides adequate confidence in the regulatory process and
the achievement of the Government’s policy target under the EPP.
57.
To protect the poor, NERSA has differentiated tariff increases for different categories of
residential customers. While the average cumulative price increase of electricity sold by Eskom in
FY11-FY13 will be 98%, the total cumulative price increase for clients consuming less than 50
kilowatt hours (kWh) of electricity per month will be only 11% and for clients consuming more than
50 kWh, but less than 350 kWh per month will be 28%. In 2003, Government launched the Free Basic
Electricity (FBE) policy (see Box 5). This policy aims to serve the poor by providing 50 (kWh) of free
electricity per month (for a sense of scale one kWh can run a small business kiosk for a day; 50 kWh
per month is enough for 3 lights and to run a small appliance like a TV or a refrigerator). Local
governments determine who qualifies for free basic services under provincial criteria set for registering
households. Today free basic electricity is provided to about 3 million households in South Africa (or
27% of the customer households).
58.
The ongoing global financial crisis and Eskom’s recent credit rating downgrades have
severely impacted the ability to finance planned investments. The New Build Program was
envisaged to be financed on the balance sheet (corporate financing approach). A large portion of the
investments was to be financed with long-term debt from domestic and international commercial
markets and Export Credit Agencies (ECAs). Even though the investment needs were large prior to the
financial crisis, Eskom was confident of raising the net borrowing requirements from the then deep
43
Generally about 40-50 percent of investment programs are covered by internal cash generation.
20
domestic and international commercial markets and export credits. In addition, appropriate tariff
increases were projected to ensure suitable internal cash generation. Now, however, Eskom does not
have sufficient levels of reserves and equity on its balance sheet to fund its complete investment
program. Commercial financing in and outside South Africa for Eskom has dried up and is only
available for short tenors. The regulatory mechanism will take time to catch up with the tariff levels
needed to address funding needs. Lack of adequate long-term funding has led to delays in parts of the
New Build Program.
Box 5: Electricity Tariffs and the Poor
The structure of electricity retail pricing in South Africa is similar to practice in OECD countries. Tariffs reflect cost of
supply and therefore households pay more for per-unit electricity consumption than major, high-voltage industrial users. For
example, in the U.S. households pay on average US cents 10 per kWh, whereas industrial users pay about US cents 6.0 per
kWh on average. In U.K. the corresponding averages are equivalent of about US cents 18 and 11 respectively.44
Recognizing that poor consumers cannot afford electricity at cost-recovery tariffs, Eskom, supported by a subsidy scheme
through GoSA, implements the FBE scheme for its consumers (as Municipalities and local government distributors do for
theirs). The FBE provides 50kWh of free electricity per month to poor families (covering 27% of customer households).
Generally municipalities do not charge consumers under FBE any access fees. Those consuming less than 50kWh per month,
but not declared indigent received a lower increase (11%) for the first 50kWh compared to the increase (22%) for between
51-350kWh per month consumption customer category. These two categories cover most households – certainly all poor
households. Tariffs for customers using up to 350kWh (average township household) is usually 25% lower than for
customers who consume more than 350KWh. Though tariff hikes affect everyone, selective allocation of price increases
among various categories protects the poor.
Outside the FBE, the recent NERSA decision also provides guidance to municipalities on average municipal electricity tariff
level benchmarks for future periods. NERSA benchmarks for next year residential tariffs are: R54-60 cents for consumption
below 50 kWh per month, R58-64 cents for consumption between 50 to 350 kWh per month, R71-76 cents for consumption
between 351-600 kW per month cents per kWh, R93-90 cents for consumption above 600 kWh per month.
Currently, there is a significant variation among tariffs of different municipalities. For example the current residential tariffs
in Pretoria and Johannesburg (including Soweto) are already above the next year benchmark for municipalities. This makes it
very difficult to estimate what would be the exact tariff increase in these two cities – it will be a Municipal level decision.
The current residential tariffs are: R60 cents per kWh (US cents 8.0) in Johannesburg for up to 500kWh per month, and R74
cents (US cents 10.0) in Pretoria - the latter doesn’t depend on the amount of consumed electricity.
59.
Until full cost-recovery tariff levels are achieved, large amounts of GoSA and
development partner financing will be required. The GoSA provided a R60 billion subordinated
loan to Eskom in 2008, which is being disbursed over three years, with almost 70 percent disbursed to
date. In addition, in February 2009, the GoSA committed R176 billion of its guarantee authority to
support Eskom borrowings over the next five years. The proposed IBRD financing (along with the
recently approved AfDB loan) supported by the GoSA guarantees would allow Eskom to finance a
significant portion of its investment needs related to the New Build Program (in particular the Medupi
Power Plant). A financing gap for the larger investment program in the sector will still remain and the
GoSA and Eskom are exploring ways to close this remaining funding gap.
B.
Rationale for Bank Involvement
“Given the new challenges arising from the dramatic changes in the global economic environment, the main focus in the
current period is to minimize the impact of the economic downturn on the country’s productive capacity as well as jobs and
poverty-reduction measures, to identify opportunities for new areas of growth and economic participation, and progressively
to set the country on a new growth and development path. Fundamental to the attainment of all our objectives is a growing
economy, appropriately transformed, so that the benefits of growth are shared by all. In this regard, the programmes we
undertake should aim at reducing inequality.” The Government’s Medium-Term Strategic Framework for 2009-2014.
44
The long term contracts for power supply to smelters (Special Purchase Agreements - SPAs) represent only a small fraction
of Eskom’s total electricity sales and their impact on the company’s financials is not significant. In the 2009 financial year
SPAs accounted for only around 5% of all electricity sales of Eskom. The terms of these contracts are confidential and cannot
be released by Eskom. Tariff increases in these contracts are linked to changes in the commodity prices and will not be
affected by NERSA decisions.
21
60.
The Government’s main objectives are to return the country to a path of accelerated, more
shared growth, to reduce unemployment and poverty within a reasonable time frame, and to ensure
stable, sustainable macroeconomic framework. The country’s resolve has been seriously tested by the
ongoing global financial and economic crisis. But it has done well in containing the damage with
timely countercyclical macroeconomic responses. The challenge for South Africa now is to position
itself for the recovery. On the basis of the energy crisis experience of 2007/08, this recovery will be
thwarted by energy shortfalls unless these are addressed in a timely fashion.
61.
The current CPS was discussed by the IBRD Board of Executive Directors in January 2008
and a Progress Report has been prepared. The strategic objectives of the CPS are to support South
Africa’s development programs in partnership with the World Bank Group and to deepen collaboration
in the regional integration agenda. Although the support was primarily designed as a knowledge and
technical support partnership at the time, the CPS allows for flexibility, being demand-driven and
responding rapidly to emerging needs. This is the case with the proposed support to the energy sector.
The CPS Progress Report, which is being processed along with the SIL, provides an update on the
progress made in CPS implementation to date and proposes the prospective Bank support to the
electricity sector. The CPS progress report seeks to extend the Bank- South Africa partnership to
analytical work to help catalyze private sector financing of planned renewable investments and
development of low-carbon options.
62.
The proposed project will support the Government’s poverty alleviation efforts by avoiding
electricity shortfalls in the medium term. Such shortfalls would lead to slowdown in growth, cause
significant job losses and severely impact the poor. Delays in returning these entities to full operation
would increase unemployment and heighten social inequalities and the risk of civil instability. In
addition, lack of electricity supply would reverse the significant gains the country has made in access
expansion and the associated social and economic benefits, including improved water supply,
institutional facilities such as rural schools and hospitals, as well as increased industrial and
commercial activities in rural areas. A further slowing of the electrification program, along with the
power shortages would seriously impact the GoSA goals of universal access for electrification.
63.
Conforming to the Government request for support, the proposed project will provide
financing to Eskom (guaranteed by the GoSA) in the midst of a difficult financial crisis. This
financing support is critical for sustaining South Africa’s and the region’s continued economic
development by ensuring adequate electricity supply. Without the proposed project, energy
investments will face delays, thus reducing the availability of supply in the country and the sub-region.
South Africa would not be able to embark on the aggressive implementation of its low carbon
initiatives such as investments in renewable energy, energy efficiency and shift in transport modes
without this project.
64.
The recent global financial crisis has tightened the international as well as the domestic credit
markets. This has compromised South Africa’s ability to respond to the funding challenges facing the
power sector. Decreased availability of low-cost capital with long tenors45 not only limits Eskom’s
ability to access new funding, but has also compromised its financial position. The proposed
IBRD/CTF financing will bridge the financing gap of the Eskom Investment Program. The Bank is
being called upon to play its role as “lender of last resort” amidst the financial crisis. The proposed
Bank support will also send a signal to private financiers regarding the credibility of Eskom’s
Investment Program.
45
In fact, according to the Bank’s Public-Private Infrastructure Database, private investments in new infrastructure projects in
sub-Saharan Africa declined by 22 percent in 2008 and investment in new infrastructure projects dropped by 73 percent to
only US$570 million. In the energy sub-sector, only four countries implemented seven greenfield projects for power
generation, involving investment of US$522 million and a total capacity addition of 366 MW.
22
“For South Africa, the major contributor to our emissions of Green House Gases is our energy sector. However, the issue for
developing countries like ours is not merely about addressing our Green House Gas emissions but also about energy security
and energy access as well. The greatest challenge we face is how to ensure both energy security and access as a
developmental imperative and at the same time laying the foundation for moving towards a path of low carbon growth.
As such, South Africa, being a responsible global citizen and in line with its obligations under article 4.1 of the United
Nations Framework Convention on Climate Change acknowledges its responsibility to undertake national action that will
contribute to the global effort to reduce greenhouse gas emissions. In accordance with this, South Africa will undertake
mitigation actions which will result in a deviation below the current emissions baseline of around 34% by 2020 and by
around 42% by 2025. This level of effort enables South Africa’s emissions to peak between 2020 and 2025, plateau for
approximately a decade and decline in absolute terms thereafter. This undertaking is conditional on firstly, a fair, ambitious
and effective agreement in the international climate change negotiations under the Climate Change convention and its Kyoto
Protocol and secondly, the provision of support, from the international community, and in particular finance, technology and
support for capacity building from developed countries, in line with their commitments under both the Framework
Convention on Climate Change and the Bali Action Plan.” Excerpt from a Statement from South African Presidency,
December 6, 2009 for COP15 in Copenhagen.
65.
The proposed project would strongly support interventions on mitigation of climate change. In
this respect, it would support the GoSA, through an IBRD Loan and the proposed subsequent CTF
concessional financing, in implementing high-impact elements of the low carbon strategy to achieve
the mitigation scenario endorsed by Cabinet in 2008. The proposed IBRD/CTF co-financed CSP plant
would be a flagship activity: as the largest facility using central receiver technology, it would establish
cost and performance benchmarks for the broader deployment of CSP technology in the country and
potentially in the sub-region. The replication potential is significant. However, currently CSP has a
levelized cost of electricity two to three times that of supercritical coal-fired power plants and very
limited operational experience at scale. The Eskom plant would help buy down costs and risks for
subsequent IPPs, interested in entering the sector thanks to South Africa’s attractive renewable energy
feed-in tariffs, but constrained by uncertainties related to cost and risks. Similarly, the strong potential
for scaling-up to utility-scale wind power faces major barriers such as high costs relative to coal-fired
production, inability to provide baseload power due to output intermittency, and incremental
transmission costs to connect isolated wind power sites to the grid. In the absence of Bank and CTF
support, the current economic crisis will further delay the implementation of the renewable energy
projects.
66.
Bank support to the energy sector in South Africa will enable the continued development of
local and regional renewable energy sources that could contribute significantly to the country’s energy
mix over time. The project will thus ensure that South Africa’s success to date in leading the subregional leadership in support of a low carbon and pro-poor energy sector is not derailed. Further as a
leader on the continent, South Africa would help demonstrate large scale renewable generation, thus
driving the renewable industry and the private sector towards future investment on the continent.
67.
The proposed project will provide financing at a time when Africa’s largest economy faces
unfavorable conditions in accessing foreign financing due to the global financial crisis. The Bank’s
supportive role would help South Africa meet the long term financing needed for addressing its urgent
need for energy and avoid a heavy economic toll on South Africans, particularly the poor.
68.
The Bank’s partnership, besides meeting immediate pressing financial needs, also creates
opportunities for sustained engagement on the “greening” of South Africa’s energy sector consistent
with the government’s low-carbon strategy and IRP; and begins to strengthen the opportunities for
realizing real progress in regional energy integration in the SADC (and SAPP countries).
69.
Bank strategies support energy access in Africa from all sources, in a manner that is consistent
with both the World Bank’s Africa Action Plan46 and the Clean Energy for Development Investment
46
Meeting the Challenge of Africa’s Development: A World Bank Group Action Plan, World Bank, September 26, 2005, and
Progress Report, September 2009.
23
Framework.47 The proposed project also responds to the African Regional Action Plan for MICs in
that the project outcomes would benefit not only South Africa but the entire region. More broadly, it
presents an opportunity to deepen the Bank’s engagement with South Africa, to establish mutual trust
and reinforce Bank support for development of the country and the region.
70.
In view of the above and as summarized in Table 3, the project is in line with the approach to
provision of energy from coal presented in Development and Climate Change, A Strategic Framework
for the World Bank Group (DCCSF),48 which was reinforced by the Board during its discussion of the
World Bank Group Energy Strategy Concept Note.49
Table 3: Assessment of the Proposed Project against DCCSF Criteria
DCCSF criteria
Project Assessment Summary
Demonstrated developmental impact of the project
including improving overall energy security,
reducing power shortage, or increasing access for the
poor
 Supports regional and domestic energy security by
increasing capacity through improved efficiency and
additional capacity.
 Allows for expansion of access to the remaining onefifth of the South African population, and higher
unsupplied populations of neighboring countries.
Assistance is being provided to identify and prepare
low carbon projects
 A CTF investment plan has been endorsed, which
supports energy efficiency measures, and includes
private sector and municipality-led Solar Water
Heater programs.
 Project is mobilizing additional financing for new low
carbon technologies, including wind power and
concentrating solar power.
 South Africa is taking significant steps on R&D
related to carbon sequestration and underground coal
gasification with its own resources.
Energy sources are optimized, looking at the
possibility of meeting the country’s needs through
energy efficiency (both supply and demand) and
conservation
 Energy strategy includes demand side efficiency
improvements and is expected to realize 3,000 MW
(equivalent to one power plant) in three years.
 RE Strategy aims at adding 10,000 GWh (1,700 MW
equivalent) of energy from renewables led by the
private sector by 2013.
 The Government is implementing other efficiency
measures, including Road to Rail transport and Bus
Rapid Transit.
 On their own, the measures cannot meet the country’s
demand growth.
47
Clean Energy for Development Investment Framework: The World Bank Group Action Plan, March 28, 2007.
Development and Climate Change: A Strategic Framework for the World Bank Group: Technical Report (DCCSF), World
Bank Group, 2008.
49
World Bank Group Energy Strategy Concept Note, CODE2009-0052, July 8, 2009.
48
24
DCCSF criteria
Project Assessment Summary
After full consideration of viable alternatives to the
least-cost (including environmental externalities)
options and when the additional financing from
donors for their incremental cost is not available
 Integrated resource planning has been undertaken by
the GoSA – no other feasible alternatives are present
that could substitute for the proposed plants –
domestic or regional.
 Domestic or regional alternatives cannot meet the
required baseload capacity (9,600 MW over 5 years).
 Even if the technology was available for renewable
base load plants such as CSP, additional financing for
the incremental costs of this size is not available.
Coal projects will be designed to use the best
appropriate available technology to allow for high
efficiency and, therefore, lower GHG emissions
intensity
 The Medupi plant will use supercritical technology.
 South Africa has decided to construct coal power
plants only with super-critical or superior technology.
An approach to incorporate environmental
externalities in project analysis will be developed
 The project considers GHG emissions in evaluating
options. Combinations of load shedding, diesel
generation and other technologies, if viable, will be
compared with the proposed plants to identify
switching values of CO2/tone equivalence. A
portfolio approach to reducing carbon footprint has
been proposed by the GoSA.
71.
An external Expert Panel was established in October 2009 to review and advise on the
application of the Bank’s DCCSF criteria and the Analysis of Alternatives for the proposed project.
The Panel’s terms of reference cover a review of the project design to assess consistency with the
DCCSF criteria. The final report of the Expert Panel has been made available to the public.
Box 6: Expert Panel Review, an extract from the Conclusions50
Final Report Dated February 18, 2010
”South Africa is facing an immediate shortage of electric power that has already crippled its economy. Hence as a transition
strategy in the near term we accept that it is necessary to build additional coal-fired electric power units. But this must be
coupled to a longer-term strategic shift to an economy based upon a low carbon energy supply.
The finding of this Expert Panel is that it is essential to help to accelerate the move of developing countries like South Africa
into an era of more and better energy services, a more energy and economically efficient economy that produces substantially
lower carbon emissions using sustainable energy sources. The focus needs to be on sustainable development that does not
add to the environmental, economic and climate burden. Linking large additions of coal-fired capacity to the implementation
of a long term low carbon strategy, coupled with immediate energy efficiency and renewables investments is one way to avoid
having a major rise in heat trapping gases into the atmosphere just as the world is moving to reduce them. Fortunately, the
South African government has already taken actions to move in this direction, and indicated that it has a long-range plan to
do so as well as initiatives currently being implemented as part of this plan. It is our recommendation that the World Bank
work with South Africa to achieve that goal for its own citizens and to assist neighboring nations that rely on the power
production and economic activity of South Africa to do the same.”
72.
While finding the proposed Project consistent with the DCCSF criteria, the Expert Panel
identified the need for Bank support to South Africa especially in the areas of low carbon energy
development and energy efficiency as well as the need to develop other cleaner options for the future.
The Panel recommended that the Bank’s long-term commitment to the above areas should be on a
scale that matches its commitment to the project. The Panel also suggests that Bank continue to
support South Africa’s efforts to demonstrate its CCS potential.
50
http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY2/0,,contentMDK:22388829~pagePK:210058~pi
PK:210062~resourceurlname:ExpertPanelFinalReport%5E$%5Epdf~theSitePK:4114200,00.html
25
73.
In this spirit, the Expert Panel has recommended several measures. While several of these are
outside Eskom’s direct control, they are mostly part of the GoSA’s low carbon strategy. They include
DSM, solar water heating, and various demand side energy efficiency measures. The panel has also
recommended scaling-up financing for the installation of CSP plants subsequent to the 100- MW
Upington plant under the proposed project, developing renewable energy-based distributed generation,
as well as improving supply-side efficiency in power plants and other facilities. Specific to Medupi,
the Panel has recommended consideration of solar pumping for the large amount of water the power
station will need. It has also recommended that power plants should allow space for the possibility of
future CCS and that Eskom should explore new technologies such as algae-based capture of carbon
dioxide, whose byproduct could be used as a fuel. Eskom’s future plants are being designed with space
for CCS and other technologies which can be used for CO2 capture are being researched in South
Africa.
74.
With regard to the recommendation of the Experts Panel, South Africa is currently pursuing
initiatives in the following areas:
(a) expanding carbon-saving public transport;
(b) implementation of a nation-wide CFL distribution program;
(c) capacity building by training engineers, inspectors, government regulators and
financial experts in energy efficiency, renewable energy and energy finance;
(d) private sector activities in the areas of reducing heat trapping emissions from the
mining and construction industries, coal mine fires, methane leaks and reducing other
greenhouse gases; and
(e) preparation of the Integrated Resource Plan for the electricity sector by the
Department of Energy.
75.
South Africa and the Bank have agreed to strengthen the partnership in the following areas,
including those recommended by the Experts Panel to achieve low-carbon objectives, both within the
ambit of this project and beyond, and through the CPS. These areas include:
(a) enhancing energy efficiency and demand side management opportunities through
technical assistance under this Project;
(b) support to South Africa with resources from the Carbon Capture and Storage (CCS)
Trust Fund to help assess CCS options;
(c) support from CTF and IFC for a private-sector led Solar Water Heater program;
(d) IFC support through Climate Change Investment Programme in Africa (CIPA) to help
boost sustainable energy investments in Africa, including energy efficiency, renewable
energy, and cleaner production investments; and
(e) On regional hydropower, current project includes technical assistance to promote
specific regional low carbon projects such as hydropower plants in Mozambique by
developing the transmission interconnection with Mozambique.
76.
Actions to implement the adopted LTMS would mitigate GHG emissions over the medium
term. Therefore, on the portfolio basis, even though in the initial term, the emissions from the energy
sector are expected to grow, in the medium term, they are likely to fall based on the increasing share of
wind/solar and nuclear power generation in the fuel mix. Table 8 provides an overview of medium
term carbon emissions from new generation in the sector arising out of the investments supported by
this project and other DSM/renewable energy-related measures that are being undertaken by the GoSA
and Eskom. At the regional level, growing share of hydropower in the southern Africa power supply
mix would also reduce carbon intensity.
26
77.
Furthermore, consistent with the Expert Panel’s recommendation, the Bank’s engagement with
South Africa through the proposed Project will provide the Bank an opportunity to position itself in the
forefront of supporting the core development needs (enabling access to electricity) of South Africa
while managing added costs and risks of climate change in an evolving global climate policy. The
Bank intends to continue a process of constructive engagement with Eskom and South Africa, both as
a part of this Project and beyond as a part of the Country Partnership Strategy to support South
Africa’s move to low carbon economy. The proposed project will thus allow the Bank to provide a
developing country partner with customized demand-driven support through its various instruments —
from market-based financing to technical assistance and concessional funds for low carbon initiatives.
The Bank through this loan is also providing technical assistance for cross border transmission line
which will enable exploitation of the hydroelectric power potential in the subregion, including
Mozambique.
C.
Higher level objectives to which the project contributes
78.
The higher level objective consistent with the CPS is to support: (a) the GoSA’s strategy for
removal of the growing infrastructure bottlenecks on an accelerated basis; and (b) the revival of
economic growth in Southern Africa, through adequate and more reliable power supply in the context
of GoSA’s strategy to transition to a low carbon economy.
79.
The Government and the Bank have agreed to establish a long-term partnership to meet the
targets set by the GoSA’s low-carbon strategy. This Project is a first key building block of this
partnership to support South Africa as it progresses towards meeting low-carbon trajectory targets.
These elements are captured in the CPS Progress Report.
80.
The proposed Project supports South Africa’s strategic response to the impact of the global
economic crisis by providing and mobilizing significant financing for urgent investment needs. This
will advance the country’s objective to ensure a reliable, secure and affordable electricity supply that is
critical for sustaining economic growth and expanding energy access.
81.
The proposed project will also enhance South Africa’s ability to secure its energy
requirements in a timely manner and will have a large positive impact in the sub-region, while
accelerating South Africa’s commitment towards a lower carbon trajectory. Besides creating the
conditions for secure and predictable industrial and commercial growth in the sub-region, South
Africa’s energy security will also facilitate further expansion of electricity access both in-country and
for dependent neighbors like Swaziland, Lesotho and Namibia. Therefore, the impact of the proposed
operation will be felt in the Southern Africa region by enabling efforts to diversify economies, greater
private sector involvement, reduced poverty and inequality, improved competitiveness of industry and
SMEs, and improved living and economic conditions for the poor.
82.
The project is also designed to be consistent with the WBG’s and Africa Region’s MIC
strategy. It is also fully consistent with the Bank’s energy strategy and regional development priorities
in Southern Africa. The project is an important element of South Africa’s CTF Investment Plan for the
large scale deployment of low carbon technologies, and the proposed CTF loan along with IBRD
financing would provide funding for the CSP and wind power components.
II.
PROJECT DESCRIPTION
A.
Lending instrument
83.
IBRD Loan: A US Dollar denominated, commitment linked, IBRD Flexible with a variable
spread, with a 7 year Grace Period and 28.5 years Final Maturity, with all conversion options selected
with repayment dates of May 1 and November 1 of each year.
27
B.
Project development objective and key indicators
84.
The Project Development Objective (PDO) is to enable Eskom Holdings to enhance power
supply and energy security in an efficient and sustainable manner so as to support both economic
growth objectives and the long term carbon mitigation strategy of South Africa.
85.
The outcomes of the project would be measured by the following indicators, as shown in
Annex 3:
(a)
(b)
(c)
C.
Increased reliable power generation;
Increased renewable energy supply; and
Reduction in carbon intensity.51
Bank strategy for support to Eskom and project components
Bank Strategy for Support to Eskom
86.
The Bank strategy is to finance Eskom’s Investment Program which in turn supports both
immediate energy security needs (coal-fired projects) and the medium- to long-term investment needs
(energy efficiency and renewables) as reflected in the GoSA’s low-carbon growth strategy. To this
extent and as shown in Figure 6 below, identified investments will be financed through a combination
of loans from IBRD, CTF, Export Credit Agencies (ECAs), African Development Bank (AfDB), and
other development financial institutions.
Figure 6: Bank Strategy to Support South Africa’s move to a Low carbon Energy Sector
87.
The proposed Eskom Investment Support Project (EISP) will have a total project cost of about
US$13.862 billion, of which IBRD financing would amount to US$3.75 billion. Component A will be
parallel financed with AfDB and European ECAs; Component B is proposed to be cofinanced with
CTF financing52 and parallel financed with other financiers; Component C will be financed by IBRD
alone.
51
Carbon intensity will be measured by the cumulative emissions produced by all the components in the project.
A proposal for CTF supplemental financing will be submitted for consideration to the CTF Trust Fund to cofinance the
renewable energy component (B) of the Project.
52
28
Project Components
88.
The proposed project will consist of the following components, which will be implemented by
Eskom:
(a) Component A includes the Medupi coal-fired power plant (4,800 MW, based on supercritical
technology) and is expected to cost US$12.047 billion,53 of which IBRD will provide
financing of about US$3.04 billion. This loan will be provided against supply & install and
civil construction contracts for: (i) the power plant; (ii) associated transmission lines, and (iii)
Loan IDC, payable to IBRD and other lenders to the Project.
(b) Component B includes investments in renewable energy (100 MW Sere Wind Power Project
and 100 MW Upington Concentrating Solar Power Project). This component is estimated to
cost US$1.228 billion, of which IBRD will provide financing of about US$260 million.54
(c) Component C includes both sector investments and technical assistance to support lowering
Eskom’s carbon intensity through energy efficiency and development of renewable energy.
The Majuba Rail Project (shift in transportation mode from road to rail) and technical
assistance for assessing the opportunities for coal-fired power plant efficiency improvements
and for the development and implementation of domestic and cross border renewable energy
projects are envisaged under this component. This component is estimated to cost US$576.07
million of which about US$440.77 million will be financed by IBRD.
(d) As per the request from the Borrower, Eskom Holdings, an allocation for US$ 9.375 million
has been made to finance the US$ 9.375 million Front End Fee associated with the IBRD
Loan.
89.
The project comprises about US$1.804 billion of low-carbon renewable and energy efficiency
investments, of which IBRD will finance US$700 million (and CTF is proposed to finance US$350
million).55 Table 4 provides an overview of the project costs and proposed financing plan.
Table 4: Project Cost and Financing Plan (US$ million)
Name of the Component
Estimated
Required
Financing
IBRD
Energy
Security
Medupi Power Plant, of which
a) Supply & Install and Construction
Contracts (incl. Contingencies)
b) Financing Costs, incl. Loan IDC
c) Other costs, incl. development costs
Renewable Energy Power Plants, of which
a) Wind Plant (100 MW), including
development costs
b) CSP Plant (Pilot 100 MW), including
development costs
9,999.99
2,489.86
1,251.00
796.65
550
CTF
Renewable
and
Energy
Efficiency
Other Lenders,
including AfDB,
ECAs, AFD and
others56
Borrower
(Eskom
Holdings)
4,925.05
2,585.08
through
IBRD and
AfDB
701.00
796.65
445.43
110
100
782.68
150
249.375
100
135.43
383.305
53
The estimate project total cost is based on Interest during Construction directly related to debt that has been raised by
Eskom for the Medupi Power Plant. Any Eskom funding costs for its contributions to the plant from the Balance Sheet have
not been included and have been considered as Eskom equity to the project.
54
It is proposed that CTF support will subsequently provide financing of about US$350 million for Component of the Project
through AfDB and IBRD.
55
No approval is being sought for the CTF Loan in this proposal.
56
Only committed financing from bilateral and multilateral lenders have been presented. Eskom is currently under
discussions with other multilaterals and bilateral to finance the Sere Wind and Upington CSP as well.
29
Name of the Component
Energy Efficiency Investments, of which
a) Majuba Rail Line, including development
costs
b) TA for Coal Plant Rehabilitation
C) TA for development and implementation
of domestic and cross-border renewable
energy projects
Estimated
Required
Financing
IBRD
CTF
546.07
410.765
20.00
20.00
10.00
10.00
Front End Fee (IBRD) and Management Fee
(CTF)
10.00
Total
13,861.82
Borrower
(Eskom
Holdings)
135.305
0.625
9.375
3,039.86
Other Lenders,
including AfDB,
ECAs, AFD and
others56
700.14
3,750
350
5,025.05
4,736.77
90.
Component A will support the supply, installation, construction, and commissioning of the
Medupi Power Plant and the associated transmission system to evacuate electricity from the plant. The
Medupi power project has been developed on the basis of several supply and install and civil work
contracts awarded by Eskom to competitively selected companies. As noted earlier, Eskom suffered
severe capacity shortages in 2008 and current projections indicate an increasing capacity deficit which
could severely constrain the economic growth of the country. In 2005, Eskom prudently initiated work
on the Medupi Power Plant and has awarded long lead-time contracts and initiated construction
activities to ensure that the construction timeline for the plant is not derailed. Eskom has procured
these contracts based on the Eskom and GoSA procurement policies and procedures, which, while well
organized, are not consistent with the Bank’s procurement guidelines. Procurement for all of these
contracts has been initiated and in almost all cases contracts have already been awarded, of which
some have been signed and work started.
91.
To ensure that the construction timetable for Medupi is not derailed, it is proposed that
Component A supports financing of contracts already awarded and where Eskom currently does not
have any committed financing. This would mean that the Bank will finance contracts that have
already been procured and awarded. Of the US$3.04 billion proposed for this component, it is
expected that US$1,776 billion (excluding US$130 million of contingencies) will be disbursed for 14
contracts already procured for the Medupi Power Plant. In addition, US$593.03 million is expected to
be disbursed for Medupi related transmission lines and two other contracts for the plant; these are yet
to be procured.57
92.
Retroactive financing is proposed to cover disbursements made by Eskom for the agreed
contracts beginning January 2007 and up to the date of signing of the Legal Agreements. It is
estimated to be 10.67 percent of the proposed IBRD Loan amount (up to US$ 400 million).
93.
The lower than anticipated increase in tariffs for the next three years has resulted in a stressful
financial situation for Eskom (see Section IV.A for details). Tariff increases alone as approved by
NERSA for FY11-FY13, without raising additional debt, may not allow Eskom to cover its immediate
debt servicing costs. To achieve financial sustainability in the near term, Eskom would need to
57
The proposal to finance interest during construction meets the requirements set out in Paragraph 1 of OP 6.00. Bank
financing of IDC is appropriate for the proposed IBRD-funded projects as the IDC forms part of the cost necessary to bring
the assets to their productive uses. In addition, a review of the financing charges that are being assessed by the multilateral
and bilateral lenders for the various components of the Project, and these have been determined to be reasonable. The Bank
will not finance any IDC related to private commercial lenders to Eskom. The proposed IBRD loan is being guaranteed by
the Republic of South Africa, and thus is a contingent liability for the South African treasury. The Team has undertaken an
analysis of contingent liabilities of the South African Government and found them to be within acceptable limits (additional
details are provided in Annex 1). The financial management risks associated with the loan have been determined to be low.
Eskom has a prudent financial management system and standard disbursement procedures will be followed for this category
of financing as well.
30
finance some of its near-term debt servicing costs for the proposed investment program. Therefore, to
maintain financial sustainability of the Bank-financed Project and of the utility notably over the next 3
years until the next tariff increase, the Borrower has requested the Bank to consider financing of IDC
in respect of the IBRD Loan and that related to other lenders to the Project. About US$550 million
will be disbursed against interest during construction (US$ 400 million on account of IBRD and US$
150 million on account of other lenders) charges and US$ 9.375 million will be disbursed as the IBRD
Front-end Fee.
94.
Eskom has completed its financing with the ECAs and is finalizing effectiveness of the AfDB
loan (of about US$2.63 billion) which was approved in November 2009. Remaining contracts related
to Component A are proposed to be financed by the Bank. Eskom’s own funds and on-balance sheet
financing (including the GoSA loans to Eskom) will also assist in financing this Component.
95.
Component B will support the development of South Africa’s first large-scale wind and CSP
plants, proposed to be implemented by Eskom Holdings. Specifically, supporting the design,
procurement, construction, supply and installation and commissioning of a 100MW wind power plant
(Sere Wind Project) and 100MW concentrating solar power plant (Upington CSP Project). Both
projects are under development by Eskom Holdings and early development work on the sites (survey
etc.) has already commenced. Component B is proposed to be cofinanced (jointly) by the CTF Loan
(when approved) and parallel financed with AFD, AfDB, Kreditanstalt für Wiederaufbau (KfW) and
the European Investment Bank (EIB). Eskom’s own funds and on-balance sheet financing (including
the GoSA loans to Eskom) will also assist in financing this Component.
(i)
Wind is a commercially mature renewable energy technology but at present there is no
significant energy generated by wind in South Africa. The Western Cape Province Wind
Energy Facility located 160 km north of Cape Town near the town of Skaapvlei, has the
potential to accommodate up to 200 MW of wind capacity. A priority activity for this
subsector is development of Phase I of this wind site – the Sere Wind Power Project,
consisting of a 100 MW wind farm comprising forty to fifty 2.0 to 2.5 MW (Class 2A) wind
turbines. The project is fully scoped and specified. The site has a “moderate” wind resource;
based on measurements completed to date at the site, it is expected that the plant will have a
load factor of 25 percent. The site is near about 40-kms from the 132-kV sub-transmission
line.
The Western Cape facility, together with new transmission capacity to export its
power, would act as a flagship to the sector. In addition, investments in transmission capacity
expansion to the key regions of potential wind power development would catalyze substantial
private sector investment under the REFIT program. IBRD/CTF funds are proposed to be used
to: partially finance the Sere Wind project, thus reducing the production cost differential
compared to coal; provide contingent financing; and finance transmission additions dedicated
to serving wind power development. Cumulative emissions savings from Phase 1 of the
Western Cape Wind Energy Facility (Sere Wind Power Project) based on annual output of 219
GWh would be 5 million tons of CO2 over an assumed twenty-year life of the plant (the 0.25
million tons avoided annually could potentially increase to 1 million tons based on other sites
already identified in the vicinity).
(ii)
CSP is the renewable energy source with the largest potential in South Africa. Gridconnected solar thermal power can provide large volumes of firm generation capacity,
comparable to what is currently provided by coal-fired power plants. However, in addition to
being more costly, the initial CSP plants will have higher risk than coal-fired power plant.
The Upington Concentrating Solar Power (CSP) plant is a tower and mirror design configured
to operate as a baseload unit. Utilizing molten salt as a thermal circulating fluid and storage
medium would allow the plant to achieve a 60-65 percent annual load factor with a rated
31
capacity of 100 MWe. The capital cost of the project is estimated at about R5 billion;
equivalent US$600 million, excluding contingencies. Given the uncertainties around the
technology, contingent financing of about US$150 million has been included in the financing
plan.
A successful CSP project will demonstrate South Africa’s role as leading the low
carbon energy agenda for the subregion, with scale-up potential in SAPP countries, including
Botswana and Namibia (with an estimated potential of over 20 GW). As such, CSP in the
medium term could play a major role in the SAPP. The proposed project would support this
development by financing a portion of the first project in South Africa. CTF financing would
be used to reduce the financing costs thus making the CSP project financially viable. The
investment would be preceded by a review of the feasibility and design work already carried
out by Eskom based on the central receiver technology. Cumulative emissions savings from
Phase 1 of the Upington CSP based on annual output of 516 GWh would be 9 million tons of
CO2 over an assumed twenty year life of the plant.
96.
Component C will support other low carbon and energy-efficiency components which would
also help improve efficiency in Eskom’s operations, including supply-side energy efficiency. This
component consists of the following three subcomponents:
(a)
The Majuba Rail Project;
(b)
Technical Assistance to support Eskom in the proposed rehabilitation of existing coalfired power plants to improve operating efficiencies; and
(c)
Technical Assistance to support Eskom to develop and implement domestic and crossborder renewable energy and energy efficiency projects.
97.
Component C.1 – Majuba Rail Project: This component includes the design, procurement,
construction and commissioning of the Ermelo to Majuba railway line that will become the main coal
transport system to the Majuba power station, consisting of a single track electrified 3kV rail line
including bridges, culverts and substations. The Majuba power station (currently operating at 85
percent of capacity) is a baseload plant. With the introduction of a heavy-haul railway line at Majuba,
it is anticipated that 100 percent of the Majuba power plant’s capacity can be generated from coal
supplied via this line in the future, which not only has a financial benefit (less costly to transport coal)
but multiple environmental and other strategic benefits as well, including eliminating the serious
accident hazard and road damage caused by coal trucks, reducing annual CO2 emissions by
approximately 250,000 tons, and freeing up capacity in the general freight railway to supply coal to the
Tutuka power station).
98.
As a railway siding used exclusively by Eskom, the capital costs associated with the proposed
design and construction forms part of the capital investment program to be funded by Eskom. Separate
environmental authorizations have been obtained for the proposed project.58 The purchase of rolling
stock does not form part of the scope. The rolling stock is to be supplied by the proposed operator,
Transnet Freight Rail, and the capital recovery, rolling stock maintenance and management of train
operations is a part of the transport tariff. Eskom intends to sub-contract the maintenance of the
servitude, the track-work, signaling, control and overhead electrification equipment to a third party.
58
Record of Decision (RoD) in terms of Section 22 (3) of the Environment Conservation Act, 1989 (Act 73 of 1989) for the
construction of the Ermelo-Majuba railway line; Environmental Authorization (EA) in terms of regulation 10(2) of the
Environmental Impact Assessment Regulations, 2006 of the National Environmental Management Act, 1998 (Act 107 of
1998) for the construction of an 88kV distribution line to supply power to the Ermelo-Majuba railway line; Mining permits
for the mining of sand, aggregate and gravel in terms of Section 27 of the Minerals and Petroleum Resources Development
Act, 2002 (No 28 of 2002); and Water Use License in terms of Section 21 of the National Water Act, 1998 (Act 36 of 1998)
for (i) impeding or diverting the flow of water in the watercourse in terms of section 21 (c), and (ii) altering the bed, banks,
course or characteristics of a water course in terms of section 21 (i).
32
99.
Component C.2 – Technical Assistance for Coal-Fired Power Plant Efficiency Improvements:
This component will support Eskom’s objectives of achieving a one percent reduction in the average
heat rate of its current fleet of coal-fired power stations by 2012. This will correspondingly reduce the
carbon dioxide (CO2) emissions from the power plants.
100.
This component will provide technical assistance to design the improvements for Eskom’s
currently operational coal-fired power plants (including Hendrina, Matimba and Kendal). The
component will finance the cost of international experts to review the work already carried out by
Eskom staff, advise Eskom on the best way forward, and prepare the associated designs,
implementation plans and technical specifications for the recommended sub-projects. In particular, the
consultants will, for each of the sub-projects, assess the feasibility of achieving the estimated heat-rate
improvements, provide advice on the proposed designs and on implementation logistics, and prepare
the associated implementation plans. It is expected that the work will serve as a model that can be
extended to the remaining power stations.
101.
Component C.3 – Technical Assistance for development and implementation of domestic and
cross-border renewable energy and energy efficiency projects. The proposed component will finance
technical, financial and legal advisory services for the implementation of the Upington CSP and other
domestic and cross-border renewable projects. Specifically, in relation to the Upington CSP, the subComponent will assist Eskom in carrying out a technical review of current assessment; a financial
review and preparation of bidding documents; an assessment of local manufacturing capability for
scale up of CSP technology; and undertaking an advisory panel consisting of international experts to
support Eskom during the implementation of the project. With respect to energy efficiency projects,
the technical assistance provided to Eskom will support a scale-up of demand side management
programs through Solar Water Heaters and assessing the potential for Time of Day metering.
D.
Lessons learned and reflected in the project design
102.
The proposed operation is the first large-scale investment operation being supported by the
Bank in South Africa. It is also the first energy operation in South Africa in recent times and hence
there is limited experience on past projects in the country. Some generic lessons learnt from the Bank’s
experience with MICs have been used to ensure sound project design and concept.
103.
Comprehensive Policy Framework is necessary for Private Investment: To encourage the
private sector, an explicit and comprehensive policy framework is required. Such policies have been
put in place in South Africa, including providing feed-in tariffs for renewable energy sources, which
will over the medium term lead to a substantial increase in private sector participation especially in
generation and energy efficiency. These policy initiatives are part of the sector enabling environment
being created in parallel with the proposed investment operation.
104.
Effective Enabling Sector Regulatory Environment is essential for Public and Private
Investment: While the sector and especially Eskom have generally performed well until recently, the
new challenges of quickly increasing generation capacity in a low tariff environment required a change
in the overall sector policy framework. Eskom will ideally need to rely on internal cash generation for
a large portion of its investment needs, which in turn will require full cost recovery from its customers.
To achieve this objective, the GoSA has issued, along with a number of other policy measures, the
EPP, which mandates a move to full cost recovery over a five-year horizon and provides the
overarching framework for NERSA. This policy is expected to provide comfort to commercial lenders
for large investment projects.
105.
Long-term Planning for Supply Side Projects is needed: The lack of investments in South
Africa in the last decade, the resulting energy crisis and the urgent investment requirements amidst a
global financial crisis have underscored the continued need for realistic planning for long-term power
33
generation projects. The GoSA is taking steps to strengthen Integrated Resource Planning and move it
out of Eskom.
106.
Planning for Low carbon Growth Trajectory should be undertaken: Experience has been that a
move to lower-carbon growth requires deliberate and tangible actions to ensure the introduction of low
carbon technologies. South Africa’s leadership in developing long-term mitigation scenarios which
are guiding its low-carbon strategy. The project design supports investment in new technologies as
well as energy efficiency.
107.
There is a Need for Effective Project Planning and Monitoring: In order to ensure timely
completion of large investments an effective planning and monitoring system is essential. Eskom’s
planning and monitoring arrangements have been found to be efficient, effective and robust.
108.
A Flexible and Pragmatic Approach is Necessary for a first time engagement: This is the first
significant engagement between the Bank and South Africa in nearly two decades and hence both the
government and the Bank know little about each other’s policy environment and implementation
procedures. This includes less than usual familiarity by South African entities with Bank requirements
in key areas such as safeguards and procurement. Moreover, the Bank also does not have full
knowledge of GoSA policies and processes, which have been found to be rigorous in most cases,
although not always fully consistent with Bank policies.
E.
Alternatives considered and reasons for rejection
109.
The planning function for public investments in the energy sector of South Africa is robust.
The Department of Energy prepares an Integrated Energy Plan (IEP) to identify future energy demand
and supply requirements. The National Electricity Regulator independently carries out a similar
national resource planning exercise. Similarly, Eskom continually assesses the projected electricity
demand and supply through a process called the Integrated Strategic Electricity Plan (ISEP).59 In mid2009, the ISEP was superseded by the Integrated Resource Plan (IRP). Through these assessment and
planning processes, the most likely future electricity demand based on long-term Southern African
economic scenarios is forecast, which provides the framework for Eskom and South Africa to
investigate a wide range of supply- and demand side scenarios and technological options to meet the
needs of the sector. As noted above, the planning and NERSA’s licensing authority and regulatory
framework provides for checks and balances to ensure against any excess capacity by balancing supply
and demand (tariff requests associated with any increase in capacity is assessed by the regulator to
meet expected demand). The Bank has review the various planning alternatives.
110.
Specifically, Eskom considered the following key variables, leading to its decision to construct
and operate the 4,800 MW Medupi coal plant: (a) fuel options (gas, diesel, LNG, coal and nuclear); (b)
import of power; (c) renewable energy options; (d) technology and unit size (taking into account
system stability, evacuation, and proven technology – FGD, dry cooling); and (e) available sites.
Alternative Fuel Sources (Component A)
111.
In 2005, Eskom, during its planning cycle for the next capacity addition, fully investigated the
various fuel options available for South Africa. South Africa has no gas reserves60 and hence gas-based
capacity is not feasible. Eskom further studied in detail the feasibility of importing LNG. However,
because of the high international price, especially given South Africa’s location, the cost of port and
59
ISEP is a robust planning tool developed by Eskom that analyzes and prioritizes the base and peak load capacity
requirements based on rigorous analyses of alternatives for supply under various demand scenarios. Based on detailed
analysis of each of the above aspects, the model compares the various generation capacity options and arrives at the optimal
mix for the power system.
60
The only available imported gas option is being exploited. Eskom has signed an agreement to purchase power from a 600
MW gas-fired plant based on gas imports from Mozambique – the only gas supply currently available in the region.
34
pipeline infrastructure required and the associated transportation costs to suitable power plant sites,
LNG was not considered a feasible option when compared to coal, which is abundantly available in the
country. Diesel was also considered as another possible option but rejected for large capacity
additions because of the high product and transportation costs. However, Eskom has established over
1,000 MW of open-cycle gas turbines based on diesel fuel to meet its peaking power needs.
112.
In the long term, South Africa intends to develop nuclear-based electricity capacity. In this
context, the nuclear option has been exhaustively studied with a last review in 2008. Development of
large nuclear capacity in the time frame of 2015/16 is not feasible. Moreover the cost of nuclear
power is substantially higher than the coal alternative and its development raises a number of issues
such as security, nuclear fuel disposal, and operational expertise, which are likely to take several years
to address.
113.
In addition to various fuel options, other regional options such as hydroelectric or other
renewables were reviewed. None of the regional hydro plants, except those in Mozambique, can
potentially supply electricity in the medium term; these plants can supply only about 2,500 MW,
which is well below South Africa’s current needs. In addition, these plants are being developed in the
private sector as IPPs, which adds an additional level of uncertainty to their commissioning schedule
and could delay the availability of power from these plants even beyond the current planned schedules.
There are no other renewable resources in the region that can be developed in the medium term.
114.
Based on comparison of alternatives and the least-cost analysis, Eskom decided that the only
feasible option to install about 9,600 MW of new baseload capacity in the medium term should be
based on domestic coal. In selecting the most appropriate means to meet demand, the IRP gave
priority to moderating the growth in demand through various energy efficiency measures. This resulted
in the demand forecast being reduced by some 3,000 MW over the first 5 years, which amounts to
about three-fifths of the capacity of a new power station like Medupi.
115.
Once this decision was made, Eskom carried out a site-selection analysis. The Medupi site,
which is located at Eenzaamheid, only five kilometers to the southwest of the existing Matimba power
station, is considered as an optimal location for the first 4,000-4,800 MW power plant due to
availability of adequate land, easier power evacuation options, and least environmental and social
impacts. Although water is available, the amount is not adequate for wet cooling, thus requiring dry air
cooling (see discussion on Eskom Expansion Plan in Annex 1 that describes analysis of technically
and economically feasible options).
Alternative Coal-Fired Technologies (Component A)
116.
Having concluded that coal-fired generation provided the only feasible solution, the next step
was to decide what technology to adopt, a key consideration being that the technology should
minimize carbon emission and should be proven to ensure reliability of supply. The technologies for
consideration were Subcritical, Supercritical, Ultrasupercritical pulverized coal, Fluidized Bed
Combustion, and Integrated Gasification Combined Cycle (IGCC). Subcritical pulverized coal had
been Eskom’s conventional technology but it was rejected due to low efficiency and high carbon
emissions.
117.
The decision to use Supercritical technology was made in 200661 and was based on the
following considerations:
(a)
Supercritical is a mature and proven technology which is the choice for most of the
new large coal power plants in large MICs such as India and China. It should be noted
61
The Bank hired Nexant LLC, a San Francisco based engineering consulting firm which has reaffirmed the choice of
supercritical technology for the Medupi Power Plant.
35
(b)
(c)
(d)
that almost 80 percent of the existing capacity in OECD, India and China is still
subcritical. China has been operating indigenously manufactured supercritical
capacity since 2005 and India is just beginning to develop new plants based on this
technology (for larger units it is still largely relying on outside vendors). Supercritical
technology enables higher efficiency of around 38-40 percent (High Heat Value,
HHV) depending on ambient conditions, compared to 35-38 percent (HHV) for
subcritical technology under similar ambient conditions. Selection of the supercritical
technology with lower carbon emissions compared to subcritical technology is
therefore appropriate.
Although a more advanced and less-polluting technology than conventional
subcritical, Fluidized Bed Combustion was rejected because it was not available in
large unit sizes, which were needed to meet Eskom’s needs. In 2006, boiler sizes were
in the range of 200-300 MW for this technology.
The next and most advanced level of proven technology, Ultrasupercritical, with
efficiency levels of around 40-42.5 (HHV) percent was not considered appropriate for
South Africa because:
(i)
The technology has a limited operational track-record in developing countries.
Other than China not many developing countries have experience in using this
technology and thus it has not been demonstrated reliably in South African
conditions. Worldwide ultrasupercritical is about 2 percent of capacity;
(ii)
Virtually all ultrasupercritical power plants under operation use water for
cooling, unlike the situation in South Africa where plants have to be designed
to use air cooling due to water scarcity (the first air-cooled ultrasupercritical
unit was commissioned in Australia only in 2007, and therefore there is a
again limited track record of performance).
IGCC technology was not considered by Eskom. The planned new capacity additions
are about 25 percent of current national capacity. Hence, it was determined that a
move to adopt a less mature technology with no operational track record for largesized power plants was operationally risky.
Alternative forms of Bank Support (Project as a whole)
118.
The Bank, the GoSA and Eskom considered the appropriateness of various World Bank
instruments to meet the urgent financing needs. A fast-track SIL was found most appropriate as the
financing is required for Eskom’s Investment Program. The GoSA in February 2009 formally
requested Bank support for Eskom’s investment program through a SIL and reiterated this request to
the Bank in November 2009.
Alternatives – Majuba Road to Rail Component (C.1)
119.
In addition to the “do-nothing” scenario, the economic evaluation of the Majuba road to rail
coal transportation project (carried out in 2004 as part of the project’s prefeasibility analysis)
compared two sets of scenarios: the Ermelo-Majuba railway line (13 MTpa); and two separate
conveyor systems, one from Elders and one from Leandra (each separately cannot supply the full coal
requirements of the Majuba Power Plant). The prefeasibility evaluations clearly indicated that the
Ermelo-Majuba railway line is the preferred option for the following key reasons: (a) shortest potential
implementation time – the Ermelo-Majuba railway line has the potential to be in operation 2 years
earlier than the conveyor systems, which will require finalization of a contract with a long term coal
supplier; (b) the implementation of the railway transport option is not dependent on the conclusion of
new coal supply contracts due to the flexibility of coal supply options (potentially more coal is
available than what is required at Majuba); (c) improved source flexibility – all future and existing
mines exporting via Transnet coal rail line will be able to supply coal to Majuba power station; (d)
36
capacity – the system can exceed 13 MTpa on relatively short notice and with limited cost impact by
using additional rolling stock; and (e) security of supply – more than one mine will supply Majuba and
there will be two alternative rail routes to Majuba, which greatly reduces the risk of non-supply.
III.
IMPLEMENTATION
A.
Partnership arrangements
120.
The project will have large amounts of joint cofinancing and parallel co-financing from
multilaterals, bilaterals and ECAs.
121.
As noted earlier, Component A is proposed to be financed (parallel) by AfDB and European
ECAs (Coface and Hermes). Eskom has secured a loan of US$2.63 billion equivalent from the AfDB
for Medupi (turbines and boilers contracts). Component B is proposed to be parallel-financed by the
CTF (joint and parallel) and development financial institutions (see Table 5).
122.
The approved CTF complete Investment Plan (IP),62 in addition to the public sector projects,
includes private sector-led initiatives involving IFC, the private sector arm of AfDB and bilateral
financiers in line with the Government’s strategy of having the private sector take the lead in
renewable energy development. As part of the CTF IP and in addition to the support for Component B
of this project, US$150 million is expected to support implementation of the GoSA’s Solar Water
Heater program and private sector-led energy efficiency and renewable energy activities. For
clarification purposes, IBRD is not financing this specific component, which will be implemented by
the private sector.
Table 5: CTF Investment Plan (November 2009)
Proposed Low carbon initiatives to be financed by CTF and other Public Lenders63
(Base Costs, excluding contingencies; US$ Millions)
CTF (thru)
Project
AfDB
IFC
EIB
KfW
AFD
Priv.
Sector
Total
Proposed
Funding
ADB
(priv)
IBRD
ADB
Sere Wind
50
50
-
110
50
-
-
140
400
Upington CSP
200
50
-
150
50
50
100
-
600
-
-
75
75
-
200
200
50
-
210
540
1,350
250
100
75
75
260
300
200
100
100
350
540
2,350
Renewable
energy/energy
efficiency/SWH
Total
IFC
IBRD
123.
In addition, the Global Environment Facility (GEF) and Public Private Infrastructure Advisory
Facility (PPIAF), both supported and managed by IBRD, have been active in South Africa. The GEFfinanced Renewable Energy Market Transformation (REMT) project is, among others, supporting the
design of feed-in tariffs for various renewable energy technologies, update of the 2003 Renewable
Energy Strategy, and small to medium energy efficiency and renewable energy investments through
the provision of matching grants. A regional PPIAF grant is supporting assessments targeted to
improve the creditworthiness of several power utilities in Southern Africa, thus enhancing their ability
to secure financing for the large power sector investment program. Additionally, a PPIAF grant will
support the South African Cities Efficiency and Renewable Energy Program, the objective of which is
to help increase investment in energy efficiency and renewable energy infrastructure through private
62
63
The CTF investment committee approved a US$500 million CTF financing plan for South Africa in October 2009.
Excludes Eskom’s equity financing for the renewable projects.
37
sector participation. PPIAF has also recently approved a grant for the GoSA that will assist in
identifying gaps in the existing regulatory environment, propose an institutional structure best suited
for IPPs in South Africa, and in particular provide advice on how the Government’s exposure to
contingent liabilities can be limited as it expands private investment in the energy sector.
B.
Institutional and implementation arrangements
124.
The first part of this section covers the implementation arrangements made by Eskom and the
second part explains the arrangements made by the Bank to ensure effective supervision of the
operation.
125.
Eskom, a wholly-owned government entity, will be solely responsible for implementation of
all components of the project and the sole beneficiary of the loan, which will be guaranteed by the
Government. Eskom has not implemented a program of this size in the recent past and has lost some
of the skills that it had then. To address this deficit the utility has been recruiting externally
specifically for the project as well as for Eskom operations and maintenance and at present is well
staffed to undertake the proposed Investment Program. See Annex 6 for Eskom’s institutional
arrangements.
126.
Component A – The Medupi Power Project: Eskom has appointed experienced engineering
houses as execution partners with the necessary skills. For Medupi, the execution partner is Parsons
Brinckerhoff (PB). PB leads the execution team, which comprises a mix of Eskom and PB staff, and
their mandate includes the transfer of skills to the local workforce.
127.
The project will be overseen by a Medupi Leadership Committee which consists of eight
senior management representatives (Chief Operating Officer (COO) / Senior General Manager /
General Manager) from Eskom and PB. The PB representatives include the COO of PB Africa and
COO of their US arm. The overall Medupi project, which includes addressing the transmission
interfacing, licensing, public liaison, industrial relations and other traditional functions, is the
responsibility of the Medupi Project Team (MPT) under the management of the Medupi Executive
Project Manager. The MPT is further supported by various divisions in Eskom; in particular, Finance,
Treasury and Corporate Services. In total, there are 38 Medupi Execution Teams (MET) for specific
contracts to review vendor design, system integration and project execution.
128.
Coal will be supplied from an existing independent coal mine (Grootegeluk), owned by
Exxaro (a private sector entity) and transported to the power plant via a conveyor system. The mine
currently supplies coal to the nearby Matimba Power Station. A Coal Supply and Offtake agreement
has been entered into by Eskom for the supply of coal to the Medupi Power Plant.
129.
Responsibility for the timely supply of water for Medupi rests with the Department of Water
Affairs (DWAF). The six units of Medupi will require about 6 million cubic meters of water per year
to operate. In addition, the FGD proposed to be installed later by Eskom will require at least another 6
million cubic meters per year. The source for the initial 6 million cubic meters will be the Mokolo
River and dam. There is currently enough water in the Mokolo River, and Eskom has permits, to
operate the first three Medupi units. To permit the next three units, and to ensure the environmental
base flow, augmentation of the current Mokolo River pipelines and related infrastructure is required.
Improvements to the existing Mokolo River system (Phase 1) include: (a) a weir and a short pipeline to
overcome a gradient and pipe bottleneck that will increase flow through by 20 percent; and (b) laying a
new pipeline parallel to the existing pipeline from the Mokolo dam to the Medupi site. Phase 1
investments will add 6 million cubic meters per year to the existing capacity and will cost an estimated
R1.9 Billion. Construction time is expected to be about 2.5 years and in time for the operation of the
last three units of the Medupi Power Plant. The GoSA is fully committed to completing the
38
investment program for water availability in a timely manner (see Section III.F for the agreed
covenant).
130.
Upon commissioning, the power plant will be handed to the Generation operations division.
Eskom has already identified staff that will be responsible for operation and maintenance of the power
plant. In preparation for operations, arrangements have been made to provide training to the O&M
staff. Consistent with best international practices, this includes on-the-job-training by the construction
contractors as well as hands-on training at similar facilities outside the country.
131.
Component B.1 – The Sere Wind Power Project: The proposed project has been developed by
the Project Development Department (PDD) within Eskom Enterprises. The Capital Expansion
Department (CED) will be responsible for the complete procurement phase. The process for every
contract that needs to be procured will be led by a dedicated staff. Upon completion of the
procurement phase (signing of a specific construction/supply & install contract), the contract will be
handed over to a project manager under CED for construction supervision and management. Operation
of the power plant will be undertaken under a proposed new “Wind” department in the Generation
Business Unit responsible for peaking plants.
132.
Component B.2 – The Upington CSP Project: This sub-component will be implemented in two
phases. The first phase will involve review of preparatory work already carried out by Eskom,
including the project concept and preliminary design. This phase will be managed by Corporate
Services. The second phase will involve procurement and construction supervision and management.
In the second phase, the CED will be responsible for the complete procurement process. The process
for every contract that needs to be procured will be led by a dedicated staff. Upon completion of the
procurement phase (signing of a specific construction/supply & install contract), the contract will be
handed over to a project manager under CED for construction supervision and management. Operation
of the power plant will be undertaken under a proposed new “Solar” department in the Generation
Business Unit responsible for peaking plants.
133.
Eskom has indicated that since Upington CSP is a pilot project to develop the long-term CSP
potential in South Africa, Corporate Services will continue to be involved throughout the project’s
implementation as well as during operation.
134.
Component C.1 ¬ Majuba Rail Project: The proposed Majuba Rail project has been wellstudied for a number of years and the technical design of this component is complete. The process for
every contract that needs to be procured will be led by a dedicated staff. Eskom has already established
a project management unit for this component, headed by a project manager, under CED, for
construction supervision and management. Transnet Freight Rail (a public entity that owns and
operates most of the rail transport network in South Africa; TFR) will provide the Eskom team expert
advice as and when required. TFR will also be responsible for engineering compliance.
135.
Eskom will construct and own the railway line infrastructure assets, while TFR will be the
rolling stock owner and operator. A Coal Transportation Agreement (CTA) will be signed between
TFR (the proposed operator) and Eskom. Within Eskom, the operation of the project will be the
responsibility of the Primary Energy department, also reporting to Generation Business.
136.
Component C.2 ¬ Technical Assistance for Energy Efficiency Improvements: The proposed
technical assistance component will be managed by a project manager within Generation Business.
137.
Component C.3 ¬ Technical, Legal and Financial advisory services for development and
implementation of domestic and cross-border renewable energy projects: The proposed technical
assistance component will be managed by a project manager within the Corporate Services
Department.
39
138.
IBRD Implementation Support: The IBRD support during implementation takes cognizance of
the size and complexity of the project, the challenges of working with a new client unfamiliar with
IBRD procedures and the arrangements required to support the use of country systems for safeguards.
It applies lessons from other operations, some of which have been referred to an Inspection Panel as a
result of unsatisfactory implementation support.
139.
To ensure a smooth transition from preparation to supervision, the majority of members of the
preparation team will continue on the team over the supervision phase. The team will comprise staff
from the Africa Region and other Regions of the Bank, as well from Anchor units, especially for
Safeguards. Use will also be made of seasoned retired Bank staff. The team will have in-depth
experience in all aspects of project implementation. Maximum use will be made of field staff, who
will work more closely with the client throughout implementation. The field staff will include team
leadership, financial management and procurement. The implementation support plan (refer to Annex
6) has been front-loaded to ensure a good support framework is in place from the outset. In addition,
the plan allows for staff exchange between Eskom and the Bank to enable knowledge transfer and
strengthen capacity.
140.
From the safeguards perspective, implementation support will be provided on two levels. On
the first level, the Bank will help support monitoring the performance of project implementation using
country systems. Bank support will involve evaluating the quality of additional safeguards documents
that may be produced, with respect to GoSA requirements and OP 4.00, and reviewing various
independent audit reports that Eskom will produce, on resettlement/land acquisition, health and safety,
and EMP implementation. On the second level, the Bank team will review results on the ground.
Safeguards specialists will join supervision missions at least twice annually and will schedule site
visits during those missions so that each generating facility with its transmission line and the ErmeloMajuba Rail Line is visited no less frequently than once a year. Facilities at which there are significant
social, environmental or health and safety concerns will be visited twice per year.
141.
At least one implementation support mission will be undertaken before the end of FY2010,
soon after the loans become effective, and three missions will be undertaken in FY2011. Missions will
also include safeguards and fiduciary staff. Implementation support will be coordinated with other
financiers such as AfDB (and other potential lenders) where possible and maximum utilization will be
made of field-based staff. IBRD implementation support is expected to cost US$2 million over the
implementation period of 5 years.
C.
Monitoring and evaluation of outcomes/results
142.
Monitoring and impact evaluation of the overall project will be the responsibility of Eskom
Holdings, with support from NT and DPE, as appropriate. The Project Coordinator (from the Finance
Directorate of Eskom) will be responsible for coordination and monitoring of progress of the overall
project. The Project Coordinator will facilitate coordination between the five project managers and
between Eskom, the shareholder (DPE), DoE and NT.
143.
The key indicators to be monitored and used in assessing project progress and evaluation of
outcomes are described in Annex 3—Results Framework and Monitoring. Specific data for gathering
and reporting, including responsibilities thereof, have been agreed with Eskom. A mid-term review
would be carried out within approximately 30 months from effectiveness of the loan. There will be an
Implementation Completion and Results Report (ICR) at the project close, to be jointly prepared by
IBRD and Eskom Holdings.
40
D.
Sustainability
144.
The proposed project is critical for the continued economic growth and energy security of
Southern Africa. In addition, it is critical to ensure that Eskom Holdings remains a strong electricity
utility and plays its ongoing role as an anchor off-taker for regional projects. The following matters
provide a sound basis for sustainability of the Project:
(a) The project is consistent with the South African LTMS and its global strategy of supporting
climate change mitigation, which defines the path of the energy sector for a low carbon economy.
To this extent, the project supports Eskom’s development of the first CSP and the wind project,
thereby opening up renewables development in South Africa and the sub-region. Replication of
these two projects will be supported by South Africa’s Renewable Energy Feed-In Tariff, which
provides IPPs with attractive incentives for investments in CSP and wind; the GoSA’s fiscal
measures (such as carbon taxes) and focus on local manufacture of clean energy technologies; and
South Africa’s substantial investment in renewable energy R&D, with a view to improving
operational performance and reliability;
(b) Even though there have been delays in the implementation of sector reforms, especially those
targeted at full cost recovery through tariffs over the medium term, significant new policy changes
have been put in place by DoE, such as the EPP and the new regulations providing the enabling
framework for private investment in power generation. This continued strong ownership of sector
reforms and commitment to Eskom by the GoSA is the foundation for continued sustainability.
Eskom’s long-term sustainability is dependent upon the MYPD3 request in 2013. As noted
earlier, NERSA has a positive track record and has already approved two multi-year tariff
increases, thereby moving the tariff trajectory towards full price recovery.
(c) The GoSA has provided continuous support for Eskom’s investment program. The current
loan of R60 billion (about 70 percent already disbursed) and the GoSA guarantee facility of R176
billion in support of the Eskom’s borrowings is a strong testament to the GoSA’s full support for
improving Eskom’s financial sustainability; and
(d) The demand forecast for electricity in South Africa has been reviewed and shows that the
proposed project is critical for maintaining acceptable reserve margins.
E.
Critical risks and possible controversial aspects
145.
A detailed Risk Identification Sheet was prepared following the Operational Risk Assessment
Framework, which is provided as a separate document. The overall risk of the operation is considered
to be Substantial considering in particular the reputational risk associated with coal and the impact of
coal-fired power plants on environment, as well as the fact that this will be the first major IBRD
operation in South Africa and will require consideration by the Board of one-time policy exception for
financing the contracts that have already been awarded.
146.
Key risks, categorized as Project Stakeholder, Operating Environment (country and sector),
Implementing Agency and Project (operation-specific) risks, are detailed below:
(a)
The Project Stakeholder Risks comprise Borrower relations, reputational risk to the
Bank and HIV/AIDS in the project area, which are considered Substantial or High.
(i)
Borrower relations – Country engagement with the World Bank (Substantial):
This is the first large SIL being proposed for South Africa after a long hiatus
and the Borrower has not been exposed to Bank processing and policies.
There is continuing concern about Bank conditionality as part of its
engagement. Ongoing implementation of the partnership strategy, knowledge
sharing, frank dialogue regarding Bank policies and procedures as well as
41
timely and high-quality response to the needs of the sector will help alleviate
these concerns.
(b)
(c)
(ii)
Reputational risk to the Bank (High): The risk of negative public perception of
the Bank’s support for coal-fired power plants is high. The Borrower has
carried out a rigorous selection process and ensured that the best proven
available technology will be adopted. A robust communication strategy has
been developed with a view to providing a clear understanding of the Bank’s
position on addressing climate change and energy access/security needs. The
main messages are that in the short-term coal investments will ensure energy
security, thus boosting the economy, while investment in renewables will help
South Africa meet its low carbon strategy and COP15 commitments.
(iii)
Reputational risk related to Procurement (Substantial): Complaints from
firm(s) that learn about the Bank’s financing of the Medupi Power Plant
contracts and may raise issues not known to the Bank during its due diligence,
or allegation of fraud and/or corruption, is substantial. The Bank will reserve
the right to refuse financing of the concerned contract and cancel the amount
allocated from the loan for contracts where fraud or corruption is established.
In the case of already disbursed amounts, reimbursement will be requested.
(iv)
HIV/ AIDS incidence around the project areas worsen (Substantial): Eskom
has an HIV/AIDS workplace program, which it extends to contractors and
suppliers, and will apply to the project sites. The program has been evaluated
by independent experts and found to be successful.
Operating Environment Risk (Country and Sector Risk), is considered to be moderate.
(i)
Economic management (Moderate): Continued sound fiscal and
macroeconomic policies gain special importance in the context of an ongoing
economic downturn – a large current account deficit in the face of
disappearing global capital flows poses a considerable macroeconomic policy
challenge for South Africa. An established record of macroeconomic policy
credibility and a sound domestic banking sector help mitigate the impact of
the financial storm and protect the longer-term economic prospects. The fact
that the country is officially out of recession is an indicator of good
macroeconomic management.
(ii)
Delays in attracting private investment in power generation and implementing
measures to improve energy efficiency (Substantial): To mitigate the risk, the
Government is modifying the incentive framework so as to make the sector
attractive for private sector investments, and strike a realistic balance between
public sector and private sector financing of the power development program.
The framework includes tariff revision; establishing an improved regulatory
framework for procurement; and implementation and operation of private
sector projects, which address potential private sector concerns. Technical
support and ongoing advice from the Bank team mitigate this risk. In addition,
the GoSA is exploring private participation in ownership and operation of
existing assets.
Project (operation-specific) risks, consisting of issues concerning the energy mix and
continued reliance on coal and sensitivity around the use of country systems.
(i)
Sensitivity around the use of country systems (Substantial): South Africa has
robust environmental and social safeguard systems in place. No specific
42
waiver is required for the Use of Country Systems. However, in order to
mitigate the sensitivity associated with piloting the use of country systems for
the first large investment operation in the country, the Project Team has
disclosed the safeguards documents in addition to the Safeguards Diagnostic
Review. Public consultation on the SDR took place in December 2009.
F.
(ii)
Absent FGD, measures to mitigate sulfur-dioxide emissions from the power
plants would not be consistent with World Bank environment health and safety
guidelines for new thermal power plants, nor with South Africa’s proposed
emissions standards for new plants (Substantial). Although the Medupi plant
is classified as an “existing” plant under South Africa‘s proposed emissions
regulations (due to the fact that the EIA was approved prior to the issuance of
the new plant regulations), the Department of Environment Affairs is planning
to designate the Waterberg airshed a priority area for air pollution control.
Thus, Eskom’s plans of and is therefore supportive of appropriate measures,
such as FGD, to bring Medupi emissions in line with ambient air limits.
(iii)
Sufficient amount of water might not be available in time for the
commissioning of the last three units or the FGD equipment (Moderate).
Progress on the project to supply the required amount of water is on schedule.
Nevertheless, the Bank has requested evidence from the Department of Water
Affairs to Eskom, committing to timely water supply.
Loan/credit conditions and covenants
Conditions for Effectiveness of the Loans:
(a)
Standard Conditions;
(b)
execution and delivery of the Guarantee Agreement, and all conditions precedent to its
effectiveness (other than the effectiveness of the Loan Agreement) have been fulfilled;
(c)
a special legal opinion satisfactory to the Bank of an independent counsel acceptable to the
Bank in connection with certain aspects of the Guarantor’s Anti-Corruption Legislation
framework.
Conditions for Disbursement:
(a)
Conditions for payments of Past Contracts under component 1 of the Project:

the Bank’s has to be satisfied that the contractor or sub-contractor who has been awarded a
Past Contract was not debarred, or suspended by the Bank at the time when the contract award
was made; and

the Bank has determined that: (a) the amendments to the Past Contracts to include the Bank’s
Anti-corruption and right to audit provisions are in form and substance satisfactory to the
Bank; and (b) its due diligence review of procurement decisions in connection with the Past
Contracts has been completed in a satisfactory manner.
(b)

Conditions for payments of Future contracts under component 2 of the Project:
the Bank has to be satisfied that adequate funds are available to the Borrower to finance the
second component of the Project from other sources than the Loan on terms and conditions
consistent with the obligations of the Borrower under this Loan Agreement.
43
IBRD Loan Covenants:
147.
Specific Anti-Corruption Covenants for Past Contracts under Part A of the Project (Medupi
Power Plant)
(a)
Except as the Bank may otherwise agree in writing, and with regard to all Past Contracts, the
Borrower shall negotiate and amend each such contract to include the Audit Right and Fraud and
Corruption Provisions in conformity with the Anti-Corruption Guidelines and as such provisions are
reflected in the Bank’s Standard Bidding Documents, including, inter alia, the definition of
sanctionable practices included in the said Anti-Corruption Guidelines and Standard Bidding
Documents and the Bank’s right to sanction a firm or individual determined by it to have engaged in
any such sanctionable practice during the bid, award or implementation of a given Past Contract.
(b)
Without limitation upon the provisions of paragraph 1 of this Section and with regard to all
Past Contracts:
(i)
the Borrower shall promptly, by notice in writing, inform the Bank regarding any
information in its possession, including non-frivolous allegations that reasonably may point to
the possibility of the occurrence of any corrupt, fraudulent, coercive, collusive and/or
obstructive practice in connection with the bidding process, the award, or implementation of
any contract to be or being financed out of the proceeds of the Loan, as these terms are
understood under the Bank’s Anti-Corruption Guidelines or the relevant Anti-Corruption
Legislation. To this end, all such information shall be provided to the appropriately named
official(s) of the Bank;
(ii)
the Borrower shall, following due consultation with the Bank, promptly take all
appropriate action in accordance with the Anti-Corruption Legislation to commence an
investigation in connection with the information referred to in sub-paragraph (i) of this
paragraph and any information provided to the Guarantor by the Bank regarding allegations of
corrupt, fraudulent, coercive, collusive and/or obstructive practice in connection with the
bidding process, the award, or implementation of any contract to be or being financed out of
the proceeds of the Loan, as these terms are understood under the Bank’s Anti-Corruption
Guidelines;
(iii)
in the event that the investigation referred to in sub-paragraph (ii) of this paragraph
confirms that either a corrupt, fraudulent, collusive, coercive and/or obstructive practice has
occurred, the Borrower shall promptly take timely and appropriate action to implement the
findings of such investigation and enforce the applicable remedies, in accordance with the
Anti-Corruption Legislation and share with the Bank evidence or any other information
identified or discovered during such investigation in connection with any such contract, it
being understood that the Bank will keep such information confidential in accordance with
confidentiality procedures that apply to its own investigations;
(iv)
the Borrower shall, in writing, adequately and regularly and, in any event, no less
frequently than quarterly, commencing with the date on which such allegations were received
by the Borrower, inform the Bank regarding any subsequent action taken pursuant to the
investigation referred to in sub-paragraph (ii) of this paragraph, and the result of enforcement
of any remedies referred to in sub-paragraph (iii) of this paragraph, including any monies that
may be recovered as a result of such action; and
(v)
in the event that the Bank may, pursuant to information referred to in sub-paragraph
(i) of this paragraph, and investigations referred to in sub-paragraph (ii) of this paragraph,
determine that a corrupt, fraudulent, collusive, coercive and/or obstructive practice, or any
sanctionable practice has occurred in connection with any Past Contract, the Bank shall have
the option, in its absolute discretion, to cancel the portion of the proceeds of the Loan allocated
44
to such contract, or require the Borrower to reimburse any amount that has been disbursed out
of the proceeds of the Loan under such Past Contract.
148.
Environmental and Social Safeguards
(i)
The Borrower shall implement the Project in accordance with the provisions of the
Environmental Legislation, the Social Legislation, the RODs, the EIA, the EMP, the RPF, the RAPs, if
any RAPs are required in accordance with the RPF, and the provisions of this Agreement. Without
limiting the generality of the foregoing, the Borrower shall exercise regular monitoring to ensure that
emissions from the Medupi Power Plant remain in compliance with the provisions of applicable
Environmental Legislation and all the terms of the ROD referred to in paragraph 206 of the SDR.
(ii)
The Borrower shall:
(a) not later than June 30, 2013, develop, adopt and thereafter implement a program,
satisfactory to the Bank, to install FGD equipment in each of the six power generation units
of the Medupi Power Plant, taking into account technical, environmental and financial criteria
in accordance with terms of reference to be discussed with the Bank, such program to be
designed such that the installation of the FGD equipment for the first power generation unit
shall commence on the later of (i) the sixth anniversary of the Commissioning Date or (ii)
March 31, 2018 or such later date as the Bank may establish following consultations with the
Borrower), and, thereafter, continue the installation of the FGD equipment sequentially, in
each case thereafter at the time each of the remaining five power generation units is taken out
of service for the first major planned outage, it being understood and agreed that all the FGD
equipment for the six power generation units shall be installed and fully operational not later
than December 31, 2021, or such later date as the Bank may establish following the said
consultations with the Borrower; and
(b) afford the Bank a reasonable opportunity to exchange views with the Borrower on such
FGD installation program at each of its preparation and implementation phases.
(iii)
The Borrower shall refrain from carrying out any Project activity that would result in the
involuntary resettlement of any person or group of persons residing in the selected site for each of the
Borrower’s UCSP, Sere Wind Power and Majuba Rail and Transmission projects (all described under
Parts B and C of the Project); provided, however, that if such involuntary resettlement would be
unavoidable, then the Borrower shall implement such Project activities in accordance with the
provisions of the RPF, including the preparation, adoption and implementation of one or more RAPs
as appropriate, all in accordance with the provisions of the Social Legislation as described in the SDR,
including without limitation, consultation with potentially Displaced Persons and disclosure of the
RAPs.
(iv)
Not later than one year after completion of the implementation of a RAP, the Borrower shall
cause an audit to be conducted by an independent qualified resettlement expert to monitor the
outcomes of the RAP, including a survey and consultation with Displaced Persons, and which audit
shall also define any necessary action to address any shortcomings in the implementation of said RAP.
(v)
The Borrower shall, not later than 45 days after the end of each calendar semester, furnish to
the Bank reports in form and substance satisfactory to the Bank, showing the volume of the water
available for the Medupi Power Plant, and the use thereof. The first such report shall be submitted to
the Bank within six months of the Commissioning Date.
(vi)
Except as the Bank shall otherwise agree, the Borrower shall not amend, abrogate or waive
any provision of any of the RODs, if such amendment, abrogation or waiver may, in the opinion of the
Bank, materially and adversely affect the implementation of the Project, or a substantial part thereof.
45
IBRD Guarantee Agreement (Government Undertakings):
149.
Environmental and Social Safeguards: The Guarantor specifically undertakes to:
(a)
complete the Environmental Management Framework (EMF) for the Guarantor’s Waterberg
district in compliance with the Environmental Legislation;
(b)
provide a copy of the draft final EMF to and afford an opportunity to the Bank to provide a
feedback to the Guarantor on the said EMF;
(c)
adopt the EMF and implement, the applicable policies and plans that are developed consequent
to the said EMF, and cause other parties to implement their projects and activities in compliance with
the guidelines for environmental management adopted through the said EMF, policies and plans;
(d)
ensure that the Record of Decisions for the Medupi Power Plant, the Upington Concentrating
Solar Power plant, the Sere Wind Power and the Majuba Railway and Transmission projects and,
when it is issued, for the transmission system associated with the Medupi Power Plant, as well as the
mitigation measures set forth and to be set forth therein, are implemented and adhered to;
(e)
take timely action to ensure adequate supply of water to the Medupi Power Plant for the
operations of the Borrower’s six units, including the FGD units; and
(f)
inform the Bank of, and consult with the Bank on, any proposal to modify any of the RODs if,
in the opinion of the Bank, the application of such proposal would result in material and adverse
environmental or social impacts upon the Project or any substantial part thereof.
150.
Anti-Corruption: The Guarantor specifically undertakes:
(a) promptly, by notice in writing, to inform the Bank regarding any information in its possession,
including non-frivolous allegations that reasonably may point to the possibility of the occurrence
of any corrupt, fraudulent, coercive, collusive and/or obstructive practice in connection with the
bidding process, the award, or implementation of any contracts to be or being financed out of the
proceeds of the Loan, as these terms are understood under the Bank’s Anti-Corruption Guidelines
or the relevant Anti-Corruption Legislation. To this end, all such information shall be provided to
the appropriately named official(s) of the Bank;
(b) following consultations with the Bank, to promptly take all appropriate action in accordance with
the Anti-Corruption Legislation to commence an investigation in connection with the information
referred to in sub-paragraph (a) of this paragraph and any information provided to the Guarantor
by the Bank regarding allegations of corrupt, fraudulent, coercive, collusive and/or obstructive
practice in connection with the bidding process, the award, or implementation of any contract to
be or being financed out of the proceeds of the Loan, as these terms are understood under the
Bank’s Anti-Corruption Guidelines;
(c) in the event that the investigation referred to in sub-paragraph (b) of this paragraph confirms that
either a corrupt, fraudulent, collusive, coercive and/or obstructive practice has occurred, to
promptly take timely and appropriate action to implement the findings of such investigation and
enforce the applicable remedies, in accordance with the Anti-Corruption Legislation and share
with the Bank evidence or any other information identified or discovered during such
investigation in connection with any such contract; it being understood that the Bank will keep
such information confidential in accordance with confidentiality procedures that apply to its own
investigations;
(d) to adequately and regularly and, in any event, no less frequently than quarterly, commencing with
the date on which such allegations were received by the Guarantor, inform the Bank regarding
any subsequent action taken pursuant to the investigation referred to in sub-paragraph (b) of this
paragraph, and the result of enforcement of any remedies referred to in sub-paragraph (c) of this
46
paragraph, including any monies that may be recovered as a result of such action; and
(e) in the event that the Bank may, pursuant to information referred to in sub-paragraph (a) of this
paragraph, and investigations referred to in sub-paragraph (b) of this paragraph, determine that a
corrupt, fraudulent, collusive, coercive and/or obstructive practice, or any sanctionable practice
has occurred in connection with any Past Contract, the Bank shall have the option, in its absolute
discretion, upon notification to the Borrower and the Guarantor to cancel the portion of the
proceeds of the Loan allocated to such contract, or require the Borrower to reimburse any amount
that has been disbursed out of the proceeds of the Loan under such Past Contract.
151.
Financial Undertaking
If the Borrower has failed to perform its obligation under the Financial Undertakings of the Borrower
under the Loan Agreement, then the Bank may issue to the Borrower a notice pursuant to paragraph
7.02(b)(i) of the General Conditions (Notice of Suspension). If such failure to perform continues for a
period of sixty days after such Notice of Suspension, then the Bank may issue to the Borrower a notice
of default pursuant to paragraph 7.06(b)(i) of the General Conditions (Notice of Event of
Acceleration). The Bank may, at any time thereafter, during the continuance of such event, notify the
Guarantor of such default, continuance and potential acceleration, which notice shall include a period
of one hundred and twenty days, or such longer period as the Bank may agree, if the Bank elects to
make a demand upon the Guarantor.
IV.
APPRAISAL SUMMARY
A.
Economic and financial analyses
Summary Economic Appraisal
152.
In the short to medium term, South Africa needs to deliver adequate power supply to continue
meeting its poverty alleviation goals and economic development objectives. This assessment finds
that it cannot meet national electricity use needs without addition of baseload capacity in the short
term, and that the most economically viable option is the development of the Medupi coal-fired
project. Over the next 20 years, according to the LTMS, South Africa’s GHG emissions are expected
to increase by 500 million tons, and Medupi would account for 6.8 percent of this growth in CO2
emissions. However, South Africa’s adoption of supercritical technology (as an initial step in its low
carbon growth) will result in an emissions savings of about 150 million tons (based on Eskom
proposed new coal plants) over this period, when compared with sub-critical coal-fired power plants.
153.
In line with South Africa and Eskom’s commitment to reduce GHG emissions, this operation
also supports investments in two other components: (a) Renewable Power Plants (wind and CSP
projects) are being developed primarily to help deliver on South Africa’s commitment to follow
mitigation strategies set out in the LTMS; and (b) the Majuba Rail Project, which would not only
reduce GHG emissions as a result of traffic transferring to the more fuel-efficient rail system, but also
result in operating cost savings for the traffic diverted to the new line. These projects would help
South Africa reduce growth in emissions immediately and are expected to play a catalytic role in the
envisaged larger-scale development of these technologies.
154.
The economic analysis has been carried out for all three components separately, and for the
project as a whole. The economic assessment for the Project covers the following main aspects. Details
are provided in Annex 9.
 Assessment of whether additional baseload power is required and whether Medupi currently
represents the least-cost option to deliver the required power. If so, assessment of Medupi’s
economic net present value.
47


Assessment as to whether the renewable energy projects (wind and CSP) are economically
viable (using a combination of economic rates of return, economic net present value and other
available information).
Assessment as to whether the Majuba railway project is economically viable (principally using
analysis of economic rates of return from the project and economic net present value).
155.
Calculating economic rates of return (ERR) – consumer willingness to pay (WTP): The total
economic benefits of the projects are assessed using the value consumers place on consuming
incremental power (represented by the area under consumer demand curve). The total WTP is
calculated by weighting the WTP by the proportions of power used by each sector. The average
consumer WTP for power in South Africa calculates to 17.54 US cents/kWh.64 The ERR has also
been evaluated at the just approved tariff with increases of 24.8% in FY11; 25.8% in FY12; and 25.9%
in FY13. The switching value of the tariff increases (required in FY14-FY19) have also been
calculated that allow for the ERR to equal the hurdle rate. Assessment of benefits at the tariff levels
provides an estimate of the lower bound of WTP.65
156.
Calculating economic rates of return – rate of discount: The discount rate used for the
assessments is 10 percent. A variety of discount rates have been used for economic analysis over the
past decade in South Africa; for the LTMS prepared for DME, 10 percent was used.
157.
Including the social cost of carbon-dioxide emissions: For each project, the economic
assessment is also carried out incorporating the value of CO2 emissions. For Medupi, this value is
added as a cost of generating power. For each of the renewable energy projects and the railway
project, this value is represented by the avoided cost due to displacement of CO2 emissions (i.e., it is
added as an economic benefit). This analysis uses a figure of $29/ton CO2 which is based on the Stern
review.66
Component A – Medupi Coal-Fired Project
158.
Eskom’s expansion plan studies have demonstrated that in order to meet South Africa’s power
needs, coal is the most economic option for meeting the baseload power requirements. This result is
also true of the low demand forecast (which includes assumptions related to lessening of the electricity
intensity of the economy and a DSM program that will reduce the 2020 load by 15,562 GWh and
3,225 MW. The economic analysis has confirmed this by a detailed examination of a range of possible
alternatives to Medupi (see Annex 9 for details).
159.
The economic analysis also indicates that the (shadow) prices of carbon as a switching value
for alternatives to the Medupi Power Plant are high, with only one exception — hydropower
developments on the Congo River in DRC (Inga III and/or Grand Inga) – US$7 per ton of CO2. More
importantly, the renewable energy alternatives to Medupi have incremental finance requirements,
beyond South Africa’s access to carbon or public finance. In part this is also a consequence of lower
load factors for renewable energy plants when compared to fossil fuel based power plants. For
example, to produce energy equivalent to the proposed Medupi Power Plant (~4,800 MW) would
64
If Medupi were a small project, and supplied only the first few kWh of this total expected increase in demand, then in an
idealized competitive retail market the energy would be bought by those with the highest willingness to pay (say small
commercial enterprises), and hence the relevant yardstick is the marginal WTP. Large industrial consumers could meet their
demand by lower cost self generation. But since Medupi is a large project, accounting for more than half the expected growth
in demand, and since in the absence of retail competition, there is no way the incremental energy can be directed just to the
consumers with the highest WTP, the energy will go to a mix of customers with a mix of WTP. Therefore, use of the average
WTP is appropriate and ensures a conservative result.
65
It is a lower bound because valuation at the tariff ignores any consumer surplus. However, because of the difficulty of
empirical verification of WTP and consumer surplus, as a verifiable indicator of WTP an assessment at the tariff is an
important yardstick.
66
Stern, Nicholas. 2007. The economics of climate change: The Stern review. Cambridge: Cambridge University Press.
48
require an installed wind capacity of 15,310 MW (at a 27 percent average load factor), with an
estimated project cost of at least US$20 billion.
160.
Once Medupi reaches full output, its gross GHG emissions are on the order of 30 million tons
per year. Over the next 20 years, South Africa’s GHG emissions are expected to increase from around
500 million tons CO2 to 1,000 million tons, an increase of 500 million tons. Medupi thus accounts for
6 percent of this growth in CO2 emissions. However, in net terms the increase in emissions would be
much less, some 10.7 million tons. This is based on the fact that if Medupi were not constructed,
electricity consumers would use diesel self-generation (in the non-domestic sectors), and candles,
kerosene and dry cells for the domestic sector. These alternatives are not free of GHG emissions.
Generation with diesel has typical emission coefficients of 710-740 gm/kWh for gasoil, and 650-700
gm/kWh for larger captive units using heavy fuels. Emissions from coal combustion at a highly
efficient supercritical plant are on the order of 900gm/kWh (gross). Alternatively, if Medupi were
simply replaced with the next best economic alternative, which is LNG in combined cycle, this would
reduce the GHG emissions to around 0.5 kg CO2 /kWh associated with a high efficiency gas combined
cycle plant. In this case net GHG emissions increase to 13.3 million tons. If Medupi were replaced by
a sub-critical plant, this would increase the GHG emissions by 7.4 percent annually, and the net GHG
emission increase would be 2.51 million tons of CO2 per year, or a lifetime increase of 75.15 million
tons CO2.67
161.
The baseline economic rate of return (ERR) of the Medupi coal project is estimated at 24.0
percent, with an economic net present value (ENPV); at a discount rate of 10 percent of US$15.7
billion.
162.
The ERR at the existing average tariff (about 4 UScents/kWh) is negative, which points to the
importance of raising electricity tariffs. Under the tariff increases just approved by the regulator
(24.8% in FY11; 25.8% in FY12; and 25.9% in FY13 (nominal) - and no increases in real terms
thereafter), the ERR increases to 2.47%. Under the tariff scenario that allows for financial
sustainability of the Company (assumed 12.5% increase in FY14 and FY15, and one percent above
inflation thereafter), ERR increases to 8.13% (at which point the tariff is 8.9 UScents/kWh). However,
as noted, this is a lower bound of economic returns: indeed, the consumer group with the lowest WTP
is large industry (which in the absence of the power provided by Medupi would use captive generation
based on fueloil), and which has a WTP of around 12 .7 UScents/kWh, demonstrably above this lower
bound. The switching value of the tariff increase required in FY14-FY19 is 5.4% above inflation.
163.
The robustness of these economic returns to the main risk factors has been confirmed based on
an extensive sensitivity analysis as demonstrated in Table 6.
Table 6: Medupi Power Plant – Summary Economic Analysis
Risk factor
Construction cost increase
World oil price (no change in Medupi coal
price)
Consumer WTP
Value of Medupi coal
Lower than expected plant efficiency (net)
Average annual plant factor (first year)
Opportunity cost of water
Plant life
67
Baseline
Assumption
Units
Switching
Value
(ENPV =0)
Assessment
of Risk
$/kW
2,203
6,131
very low
US$/bbl
75
17
very low
UScents/kWh
US$/ton
[%]
[%]
Rand/m3
years
17.5
31.9
37.5%
90%
20
50
10
155
0.08
39%
>200
5
low
extremely low
extremely low
extremely low
extremely low
extremely low
Based on an estimated plant life of 30 years.
49
164.
Impact of GHG emissions: The ERR decreases from 24.0 percent to 21.5 percent when the net
increase in GHG emissions is taken into consideration with a CO2 valuation of US$29/ton.68 The
sensitivity analysis of economic returns against the CO2 price shows a shadow price of CO2 (i.e., the
value of CO2 emission reductions at which the project would be equal in economic viability to the
Medupi power project) of US$142/ton (see Figure 3 in Annex 9). This is almost twice the higher
estimate provided in the Stern Review of US$85 per ton CO2.
165.
The analysis of GHG emissions has also been assessed on the basis of life cycle emissions.69
In the case of Medupi, this increases gross GHG emissions, with a slight decrease in ERR from 21.5
percent to 21.3 percent. But in such an analysis the emissions of other options also increase.
Consequently the carbon shadow prices also change: in the case of LNG from $105/ton CO2 to
$135/ton CO2, because of significant emissions in liquefaction and transport, and small decreases in
shadow price relative to the renewable energy alternatives and nuclear power. The details of the life
cycle GHG emissions analysis are provided in Annex 9.
166.
The robustness of the project to exogenous uncertainties has also been examined in a scenario
analysis: two scenarios have been assumed:

Optimistic scenario: robust global economic growth leading to increasing world oil and
commodity prices, and hence higher costs of coal (and also a higher WTP as oil prices
increase). Construction cost overruns are also likely in this scenario as equipment prices
increase in a seller’s market when order books are full, and steel prices are high.

Pessimistic scenario: lower economic growth, high damage costs to South Africa from climate
change leading to less-than-expected electricity demand growth and increasing water
shortages. This is coupled with disappointing project performance – less-than-expected
efficiency, construction cost overruns.
167.
The results of this scenario analysis are shown in Table 7. As expected, the downside risk
exceeds the upside risk. However, even under the worst case scenario (low world oil price,
construction cost overruns, and low consumer willingness to pay), the ERR falls from 23.9 percent to
16.0 percent, and when higher GHG damages are included in the pessimistic case, the ERR falls to
10.6 percent, slightly above the 10 percent hurdle/discount rate.
Table 7: Medupi Power Plant: Economics – Scenario Analysis
ERR
ERR including GHG
damage costs
Pessimistic
16.0%
Baseline
24.0%
Optimistic scenario
25.8%
10.6%
21.5%
23.9%
168.
Based on the above analysis, it is concluded that the Medupi Power Plant is economically
viable, has high economic returns and that the returns are robust to wide ranges of uncertainty in
assumptions. Hydro and nuclear options are also part of Eskom’s expansion plans, and are
complements to rather than substitutes for Medupi. Moreover renewable energy alternatives (wind
and CSP) have carbon shadow prices far in excess of the likely social costs of carbon.
68
The $29/ton valuation is based on the Stern Report (see Annex 9), and is also roughly equal to the 2008 EU ETS price.
However, 29$/tonCO2 is significantly higher than the 2008 CDM market price of (US$16.8/ton in the primary CDM market).
69
This includes emissions over the entire life cycle of a technology (including construction and decommissioning), and the
emissions across the entire value chain (for example, in the case of LNG, includes emissions associated with flaring,
liquefaction, transport and regasification; or in the case of coal, in coal mining, and coal transportation). The life cycle
emissions for mine-mouth coal projects such as Medupi are lower than those associated with imported coal involving long
transportation distances.
50
169.
The net GHG emissions of Medupi must be placed in the context of the Government’s overall
program to achieve a lower-carbon expansion path. Analysis was conducted to compare the net
emissions of the DSM program, the renewable energy target under the REFIT program, and the
Medupi power project. To carry out a conservative assessment, it is assumed that the 10,000 GWh RE
target is reached four years later – in 2017 – and that the Medupi project is replacing gas-fired (LNG)
generation. As shown in Table 8, CO2 emission savings from the GoSA DSM program and the REFIT
renewable energy program exceed the incremental emissions from the Medupi Power Plant for the life
of the coal-fired power plant.
Table 8: CO2 Emissions – Medupi Power Plant v/s GoSA REFIT & DSM Programs
DSM program
Energy
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
GWh
[1]
428
662
1,156
3,058
5,291
7,140
8,782
10,477
12,172
13,867
15,562
Renewable energy program (REFIT)
Avoided CO2
emissions
mtpy
[2]
0.4
0.7
1.2
3.1
5.4
7.4
9.0
10.8
12.5
14.3
16.0
Avoided CO2
emissions
mtpy
[4]
0.00
0.52
1.03
2.06
4.12
6.18
8.24
9.27
10.30
10.30
10.30
Energy
GWh
[3]
0
500
1,000
2,000
4,000
6,000
8,000
9,000
10,000
10,000
10,000
Medupi
Total
[2]+[4]
mtpy
[5]
0.4
1.2
2.2
5.2
9.6
13.5
17.3
20.1
22.8
24.6
26.3
Net CO2
emissions
mtpy
[6]
2.4
7.2
11.5
15.6
16.7
16.7
16.7
16.7
Net impact
[5]-[6]
Net CO2
emissions
mtpy
[7]
-0.4
-1.2
-2.2
-2.8
-2.4
-2.0
-1.7
-3.3
-6.1
-7.9
-9.6
170.
Incremental Financing Requirements to replace Medupi with Renewable Energy: While the
carbon shadow price conveys a relative measure of GHG efficiency for the alternatives, a more
practical measure of the incremental costs of GHG emission-free alternatives is the amount of carbon
finance required to cover the up-front investment. Table 9 shows the total completed financial cost of
Medupi and its alternatives.
Table 9: Incremental Finance Requirements
(project scaled in size to deliver the same energy output as Medupi)
Technology
Incremental Finance Requirement
US$ billion
CCGT-LNG
CCCT(HFO)
Hydro(Inga-III as the sample project)
Underground Coal Gasification
Medupi Power Plant
Nuclear
Wind
Concentrating Solar Power
CSP storage
-9.3
-8.5
-4.7
-1.9
19.6
20.5
25.4
31.5
171.
Renewable energy alternatives to Medupi score best on the GHG emission attribute, but have
significantly higher financing requirements, which far exceed what can reasonably be expected from
the presently available carbon financing sources. Wind and CSP would require about US$20-25
51
billion of additional carbon finance, 30-40 times the financing provided by CTF and IBRD for the
wind and CSP components of the proposed project. This level of carbon or public finance at present is
not currently available to South Africa.
Component B – Renewable Energy Projects - Sere Wind Power Project and Upington CSP
172.
The catalytic role of the proposed Sere Wind and Upington CSP projects in developing future
renewable projects is the driving force behind their current development. Assessing these projects as a
source of incremental power alone would fail to capture the full benefits of these investments. They
are being developed primarily to help deliver on South Africa’s commitment to follow mitigation
strategies set out in the LTMS.
173.
The two projects – as a first of their kind in sub-Saharan Africa – are seen as a test case and
catalyst for larger scale delivery of power using these technologies to displace considerable future CO2
emissions (and generate economic externality benefits in the process) and are very much a response to
the need to support the Government in operationalizing its plans under the LTMS. GoSA’s strategy on
mitigation requires such projects to be developed, and assessment of economic viability of each of
these projects should therefore take account of their broader role in making future economically
attractive projects take place earlier and in greater numbers.
Sere Wind Power Project
174.
South Africa has very little established wind power and the Sere Wind Power Project will play
a significant role in facilitating increased future investment in the sector. The project will include
investment in transmission lines that will reduce costs for future projects. It will test the
institutional/regulatory conditions and will help reduce uncertainty with borrowing, terms relating to
bankable power-purchase agreements, and the operation of the REFIT. The project will also provide
greater certainty on equipment and operating costs in the South African context. If the various cost and
risk barriers can be reduced through this project, the consensus view is that there is potential for some
4 GW of wind power in South Africa, which would make an important contribution to meeting South
Africa’s commitments to long-term mitigation targets.
175.
The results of the economic analysis using specific data available for the individual project and
treating the project as a source of incremental power alone – i.e., based on consumer WTP without
avoided carbon benefits – is calculated to be 10.7 percent, assuming a 25 percent load factor. The
ENPV has been calculated to be positive at US$9.2 million. The proposed wind power project results
in reduced GHG emissions (when compared to alternatives). Considering a valuation of US$29/ton of
CO2, the ERR increases to 14.1 percent (still assuming a load factor of 25 percent). The ENPV
increases to US$54 million. The sensitivity analysis shows that the ERR is strongly dependent upon
the achieved load factor.
Upington CSP Project
176.
The results of the economic analysis using specific data available for the individual project and
treating the project as a source of incremental power alone, i.e., based on consumer WTP without
avoided carbon benefits – is calculated to be 1.8 percent. Even though it is intended to operate at a load
factor of 60-65 percent, because of the limited long-term experience with the technology, the economic
analysis is based on a much more conservative load factor of 40 percent. At this load factor, the ENPV
has been calculated to be negative US$266 million. The proposed CSP power project results in
reduced GHG emissions (when compared to alternatives). Considering a valuation of US$29/ton of
CO2, the ERR increases to 4.0 percent at a load factor of 40 percent.70 The ERR is strongly dependent
upon the achieved load factor and rises to 9.0 percent at a load factor of 60 percent and 10.8 percent at
a load factor of 68 percent.
70
With storage the Upington CSP is expected to reach a maximum load factor of 65percent.
52
177.
Such an assessment should not ignore the wider (and currently difficult to quantify) benefits of
this project. The LTMS finds CSP to be a realistic alternative to coal-fired power plants. Eskom has
estimated that there are resources for about 40 GW of solar thermal power in the Northern Cape and
Western Cape provinces alone. The combination of scale and potential for replicating coal-fired power
generation’s dispatch ability in the system (with thermal storage) makes CSP the critical renewable
energy technology for enabling South Africa to meaningfully reduce absolute emissions by 2030 as
per the LTMS and its commitments. What is more, Southern Africa is one of a select number of
regions around the world that is particularly suited to CSP use and this project would be the largest
commercial CSP plant in operation. The IEA finds a learning rate for CSP of 12 percent (i.e., a 12
percent drop in prices every time there is a doubling of installed capacity). CSP is a technology with
significant unrealized economies of scale and there is potential for technical improvements in various
components. Initial projects such as this one are expected to significantly lower costs of follow-on
plants leading to more and/or earlier adoption of CSP globally. Given the scale of the long-term
potential for CSP globally and the displacement of CO2 emission-related costs this would entail, this is
a significant benefit from the project that is almost impossible to quantify.
178.
There are certain proxies that we can consider for quantifying the additional benefits of this
project. South Africa does not have green tariffs and it is impossible to directly observe consumer
WTP for power from CSP. It can be expected, however, that Government policy seeks to reflect
longer-term population preferences. On this basis, if the feed-in tariff set for CSP (US cent 28.0/kWh)
were taken as a proxy for higher national willingness-to-pay for power from initial CSP projects (for
the reasons linked to South Africa’s low carbon growth aspirations), the project ERR (at 40 percent
load factor and including value of displaced CO2 emissions) would rise to 9.6 percent and ENPV to
negative US$15.2 million. With a 60 percent load factor, the ERR would rise to 15.7 percent and
ENPV to positive US$248.9 million. A clear indication that there is an additional ‘global willingnessto-pay’ for such initial CSP projects can be observed from the CTF Trust Fund Committee’s
willingness to provide US$250 million in highly concessional loans towards this CSP project and a
further US$750 million specifically towards CSP projects in the Middle East and North Africa regions.
Component C – Majuba Rail Project
179.
The benefits of the Majuba railway electrification project have been calculated for the 30-year
period following project completion, from 2014/15 to 2044/45, and estimated economic internal rate of
return (EIRR) and net present value (NPV) were calculated using a discount rate of 10 percent. The
estimated NPV, discounted to 2014/15, is R3.28 billion (US$437 million) in 2009 prices with an EIRR
of 19 percent. The details of assumptions are presented in Annex 9.
180.
The project results in net savings of GHG emissions, and hence when GHG emissions are
included in the analysis, the economic returns increase (to 19.6 percent when valued at US$29/ton
CO2). The sensitivity analysis shows returns to be robust to the main uncertainties, including 50
percent capital-cost increases. Even if the analysis is restricted to benefits from the operating-cost
savings, discounting all external benefits associated with the road traffic, the EIRR is still 16 percent.
Project Economics as a Whole
181.
The aggregate project returns are dominated by Medupi, and are shown in Table 10. The
baseline aggregate project economic return is 22.7 percent, with an NPV of US$15,298 billion.
53
Table 10: Project Economics as a Whole
Component
AMedupi Coal
B.1 - Wind
B.2 - CSP
C.1 - Majuba Railway
Project as a Whole
ERR
NPV @ 10%
(as a %)
24.0%
10.7%
1.8%
19.0%
22.7%
US$ Millions
15,727
9.2
-266
437
15,907
182.
As shown in Table 11, when the changes in GHG emissions are taken into account, and based
on a carbon valuation of US$29/ton of CO2, the economic returns of the project decrease. As
expected, the bulk of the impact is attributable to the Medupi coal project, whose returns are
negatively affected as it is the only carbon-emitting project. The economic returns of the wind, CSP,
and Majuba Railway project components all increase slightly.
Table 11: Project Economics as a Whole, including CO2 valued at US$29/ton
AMedupi Coal
B.1 - Wind
B.2 - CSP
C.1 - Majuba Railway
Project as a Whole
EIRR (w/o
GHG)
EIRR (w/
GHG)
Change in
EIRR
ENPV
(as a %)
24.0%
10.7%
1.8%
19.0%
22.7%
(as a %)
21.5%
14.1%
4.0%
19.6%
20.5%
(as a %)
-2.5%
3.4%
2.2%
0.6%
-2.2%
US$ Millions
12,585
54
-206
457
12,890
Summary Financial Appraisal
183.
While operationally efficient, Eskom’s financial performance has been deteriorating since
2006. This performance broadly reflects the cumulative impact of the policies over the last decade and
the impact of the large investment program currently envisaged by the company.
184.
As is usual and customary for large utilities, Eskom Holdings has historically financed its
investment needs on its balance sheet, which also helped optimize tax efficiencies. Corporate
financing traditionally meant that Eskom would project its investment and operational needs for the
medium term and accordingly secure long- and short-term debt facilities on local and international
capital markets. The general principle under which Eskom operated was that if adequate long-term
funding could not be identified, a portion of its investment program (non-urgent capex) would be
temporarily deferred till the availability of additional funding.
185.
Given this framework, it was envisaged that the proposed Project would be funded at the
Eskom Holdings level within the overall Eskom funding plan. This would have allowed Eskom to
leverage its strong balance sheet and unique market position to achieve optimal cost funding for the
project and Eskom as a whole. It would further allow Eskom to manage its funding portfolio to protect
its credit rating in the best possible way.71 Even though the investment needs were large, prior to the
financial crisis, Eskom was reasonably confident that it would be able to raise the necessary funds
from then deep local and international capital markets. In addition, appropriate tariff increases were
projected to ensure that suitable internal cash generation was maintained.
71
Limited recourse project finance was not considered as it was expected to increase the cost of funds to the project, but also
delay the schedule due to the lead time required in raising project finance.
54
186.
The recent global financial crisis has severely impacted South Africa, and coupled with
Eskom’s recent ratings downgrade, has compelled Eskom to change its financing strategy in the
following ways:
 Secure government support to bridge investment needs: in July 2008, the National Treasury
approved a R60 billion subordinated loan to Eskom,72 and in February 2009, the South African
government committed its guarantee authority for up to R176 billion over the next five years.
Shareholder loan and debt guarantees will provide Eskom with over R200 billion or 86 percent
of its total external funding needs during the next five years;
 Seek regular tariff increases from NERSA;
 Continue issuance of local and international bonds, but lower expectations to fit market
appetite;
 Enhance access to ECA-backed funding where feasible; and
 Approach IFIs, such as AfDB and the World Bank to fill the financing gap as lenders of last
resort.
187.
Annex 10 provides a detailed financial analysis for Eskom Holdings. In summary, all of
Eskom’s financial ratios have deteriorated during the last three years due to rapid growth of operating
expenditures coupled with an increase in borrowings needed to finance the accelerated capital
expenditures program. The Operating Margin, which is an indicator of operating efficiency and
adequacy of pricing, has dropped from around 33 percent in FY06 to 17 percent in FY07, to 8 percent
in FY08, becoming negative 3 percent in FY09. Return on Total Assets decreased from 9.1 percent in
FY06 to negative 0.8 percent in FY09, while Return on Average Equity dropped from 9.5 percent to
negative 16 percent during the same period of time. The major reason for the weakening of Eskom’s
financial ratios is the fact that Eskom tariffs have been growing much more slowly than operating
costs: the average selling price of electricity during the last three years increased by 47 percent from R
cents 17.01/kWh in FY06 to R cents 24.97/kWh in FY09, while the average total cost of electricity
sold increased by 87 percent during the same period of time from R cents 14.8/kWh in FY06 to R
cents 27.63/kWh in FY09. The average total cost of electricity sold was higher than the average
selling price in FY08 and FY09. The other important factor that has negatively affected Eskom’s
financial performance is the increase in borrowings to finance significantly increased capital
expenditures: the debt to equity ratio for Eskom has risen from 0.2 in FY06 to 1.22 in FY09, while the
interest cover ratio deteriorated from a healthy 3.8 in FY06 to negative 0.7 in FY09.
188.
Tariffs. Eskom’s revenues are almost entirely regulated by tariffs set by the NERSA. The
Company’s long-term profitability and financial sustainability are dependent on NERSA’s approval of
future multi-year tariff increases. In 2006, NERSA replaced its annual rate-of-return methodology with
MYPD (Multi Year Price Determination), a forward-looking, multi-year system that sets a
predetermined tariff over a three-year period. On February 24, 2010, NERSA announced its decision
to allow Eskom to raise tariffs by 24.8% in FY 2011, 25.8% in FY 2012 and 25.9% in FY 2013. The
approved tariff increases are lower than those requested by Eskom in November 2009 (35 percent
annual tariff increase for FY11-FY13).
189.
Financial Sustainability. Financial projections indicate that tariff increases for FY11-FY13
approved by NERSA in February 2010 will limit Eskom’s ability to generate sufficient cash flows to
fully finance its Investment Program in the medium-term. A summary of the projected financial
performance and main ratios is presented in Annex 10.
190.
In order to maintain financial sustainability in the near term Eskom would need to either adjust
cash flow requirement by canceling/postponing certain projects or obtain additional support from
72
R10 billion of this amount was disbursed in FY09, while the remaining portion will become available to Eskom in FY10
(R30 billion) and FY11 (R20 billion).
55
GoSA in the form of additional equity injection and/or shareholder loans. In addition, Eskom would
need to request additional annual tariff increases of around 25 percent in its MYPD3 (FY14-FY15) in
order to be financially sustainable in the long term. Sensitivity analysis also indicates that the financial
position of the Company is vulnerable to decreases in electricity demand that could materialize as a
result of stagnation in the South African economy and/or as a market reaction to the proposed tariff
increases.
191.
Financial Analysis of Project Components: Financial analysis of each of the project
components (other than the Technical Assistance Component C.2) has also been carried out. As
shown in Table 12 below, the Medupi Power Project and the Majuba Rail Project are financially
viable. However availability of long-term, low-cost financing from IBRD and other financiers is
shown to be critical for these projects to achieve an acceptable 18 percent FIRR73 under the base case.
Appropriate sensitivity and scenario analyses have also been conducted on these results, which are
presented in Annex 10.
Table 12: Financial Analysis of Components A, B1, B2 and C1
Project IRR
Project NPV
(Rand billions)
Eskom IRR
Eskom NPV
(Rand billions)
A.1 – The Medupi Power Plant
17.5%
117
21.4%
129
B.1 – The Sere Wind Power Project
6.8%
-678
18.0%
398
B.2 – The Upington CSP
7.6%
-909
18.0%
1
C.1 – The Majuba Rail Project
30.3%
5.7
69.5%
6.5
Component
B.
Technical
192.
Component A: The decision to build Medupi was taken in 2005. Procurement began in 2006
and the first unit of the plant is planned to be commissioned in April 2012. The Medupi Power Plant
has been developed as a greenfield coal-fired baseload power plant project in Lephalale, a northern
province of South Africa, with a gross installed capacity of 4,800 MW. The plant is expected to have
an annual energy generation of 3,200 GWh and an average load factor of 84.2 percent, with a planned
load factor of about 90 percent in the early years of operation.
193.
Medupi is designed as a mine-mouth, six-unit power station with supercritical pulverized coalfired units, directly dry cooled and FGD-ready. Due to constraints on water availability and with
approvals from the Department of Environmental Affairs, the plant will be built as “FGD ready”, i.e.,
with physical space, as well as linings built into the smoke stacks, to allow for FGD installation
without excessively long outage times required. Because of the limited global experience in “drytype” FGD for large units, Eskom has decided to install “wet-type” FGD units on a sequential basis,
beginning in 2018 and completing in 2021, by which time the required amount of water is planned to
be available.
194.
A site for the construction of the plant was selected, based on a rigorous assessment of
alternatives, five kilometers to the southwest of the existing Matimba power station. Land acquisition
has been completed, with re-zoning of the land from an agricultural to an industrial site having been
completed in March 2007. The transmission system to evacuate power from the Medupi Power Plant
is being progressively developed as a part of the integrated transmission system and matching the
commissioning of the generating units at the Medupi Power Plant. It involves six circuits of 400-kV
73
Under the base case, it is assumed that Eskom will recover a nominal FIRR of 18 percent for its contribution to the project.
This assumption is consistent with NERSA’s announcement on Renewable Energy Feed-in Tariffs (REFITs) on October 29,
2009 in which the regulator indicated that it would allow renewable energy producers to recover the real weighted average
cost of capital (12 percent) plus the rate of domestic inflation (6 percent).
56
lines (with one possible 765 kV line) and construction of a switchyard and upgrading of associated
substations. Coal and water supply arrangements for plant operations have been found to be adequate
for the proposed plant design. These are further discussed in Annexes 4 and 11.
195.
The total base cost of the 6 x 800-MW project, excluding FGD, and including all development
costs, all escalation, all overheads, interest during construction74 and the cost of transmission
integration, is estimated at US$12.05 billion. The cost of the supply & install and construction
contracts is about US$10.0 billion excluding contingencies and expressed in terms of US$ per kilowatt
of installed capacity; this amounts to US$2,080/kW (at current exchange rate of R7.5=US$1) installed.
196.
The Bank has hired independent consultants (Nexant Inc. of USA) to benchmark the Medupi
cost with other similar plants contracted at the same time (around 2005-6), while incorporating the
impact of the location and any plant-specific adjustments. Their assessment is that the unit cost of
generation capacity compares well with similar plants ordered during the same timeframe in developed
and developing countries. Nexant has also undertaken a technical review of the plant design,
construction and operational arrangements. Nexant has opined that the design of the Medupi Power
Plant meets or exceeds performance, reliability and availability requirements of similar coal-fired
plants in operation or being constructed today.
197.
Component B: This component comprises renewable energy investments: the Sere Wind
Power Project (100 MW); and the Upington CSP (100 MW).
198.
Component B.1 – Sere Wind Power Project: Wind measurements are underway at the (Sere)
wind farm site. Data for a continuous 12-month period will be available in April 2010 and only
thereafter will the procurement process for the plant commence. An analysis of the data available so
far shows that optimum generation would be from 50 x 2- MW turbines, giving an annual gross output
of 219 GWh.
199.
The project is fully scoped and specified, except for the transmission links in the Western
Cape province with respect to the REFIT IPPs. Cumulative emissions savings from the Sere Wind
Power Project, based on an annual output of 219 GWh, would be 5 million tons of CO2 over the 20year life of the plant.
200.
Component B.2 – Upington Concentrating Solar Power Project: The Northern Cape Province,
where the proposed plant is located, has one of the highest solar potential values in the world, with a
Direct Normal Insolation (DNI) level of approximately 2,900 kWh/m2 per year. The proposed
Upington CSP plant is a 540- MWt tower and mirror design, configured to operate as a partial
baseload unit. The proposed CSP plant is configured with thermal storage and has a load factor high
enough to be considered as a partial baseload resource. Utilizing molten salt as a thermal circulating
fluid and storage medium allows this design to achieve a 60 to 65 percent annual load factor with a
rated capacity of 100 MWe.
201.
CSP is an evolving technology with a number of innovative developments taking place
globally. Prior to undertaking implementation of the CSP plant, Eskom plans to undertake a detailed
review of CSP-related development work already undertaken, including the proposed technology,
current design and proposed size in order to: (a) validate the proposed design; (b) optimize plant size
and design in light of current technological developments; and (c) incorporate any new and feasible
design features based on global state of the art. Based on this review, detailed feasibility work will be
undertaken followed by preparation of the bidding documents for engineering, procurement, and
construction of the plant.
74
The estimated IDC relates to loans made for the Medupi Power project and excludes all IDC associated with the funding of
Eskom Equity (balance sheet financing).
57
202.
When operational, it is expected to be the largest power facility for grid use based on CSP
technology in the world. It is a first-of-its-kind, large-scale baseload solar thermal power plant and
could lead to a pipeline of similar projects undertaken by Eskom or IPPs in South Africa. The
estimated cumulative emissions savings resulting from a projected annual energy production of 516
GWh is 9 million tons of CO2 equivalent over a projected twenty-year plant life.
203.
Component C: Low carbon Energy-Efficiency Investment and Technical Assistance: This
component consists of the following three subcomponents:
(d)
The Majuba Rail Project;
(e)
Technical Assistance to support Eskom in the proposed rehabilitation of existing coalfired power plants to improve operating efficiencies; and
(f)
Technical Assistance to support Eskom to develop and implement domestic and crossborder renewable energy and energy efficiency projects.
204.
Component C.1 — Majuba Rail Project: This component includes the design, procurement,
construction and commissioning of the Ermelo to Majuba railway line that will become the main coal
transport system to the Majuba Power Station. The Majuba Power Station (currently operating at 85
percent of capacity) is a baseload plant. By introducing a heavy-haul railway line at Majuba, it is
anticipated that 100 percent of Majuba Power Plant capacity can be generated from coal supplied via
this line, which not only has a financial benefit (less costly to transport coal) but also multiple
environmental and other strategic benefits (including freeing up capacity in the general freight railway
to supply coal to Tutuka Power Station).
205.
The proposed coal-transport project between Ermelo and Majuba is a 68-km private siding
railway link connecting a take-off point located 8 km west of Ermelo on the Transnet Freight Rail coal
export railway line to the existing Majuba Power Station rail siding and tippler. The proposed project
will also include a new rail yard layout to ensure an off-loading rate of up to 14Mtpa, but excludes
modifications to the existing Majuba Coal Stockyard System.
206.
Eskom, together with Transnet Freight Rail (TFR), has also designed the tie-in between the
coal export railway line and the proposed railway line. Eskom’s design consulting engineers have
completed the design. An agreement for the tie in and alterations to the railway line needs to be
concluded between Eskom and Transnet Freight Rail.
207.
Eskom will construct and own the railway line infrastructure assets (classified as a siding for
exclusive use by Eskom) and Transnet Freight Rail will be the rolling stock owner and operator. The
commissioning of the line is expected in January 2014. Eskom will sub-contract the maintenance of
the servitude, the track-work and overhead electrification equipment. A Coal Transportation
Agreement (CTA) is under development between TFR (operator) and Eskom. The CTA will include
the terms and conditions for the operations of the Ermelo-Majuba railway link using rolling stock
supplied, maintained and managed by TFR.
208.
Component C.2 — Technical Assistance for Coal-Fired Power Plant Efficiency Improvements:
The proposed component will support Eskom’s objectives of achieving a 1-percent reduction in the
average heat rate of its current fleet of coal-fired power stations by 2012. The proposed technical
assistance component will assist Eskom with the improvements that require external engineering
support (engineered improvements) to improve the net heat rate of the plants. In the first instance, the
proposed component will provide technical assistance to design the improvements specifically for
three of Eskom’s power plants. It is expected that the work will serve as a model that can be extended
to the remaining power stations.
209.
Component C.3 — Technical Assistance for development and implementation of domestic and
cross-border renewable projects. This component will support the implementation of the Upington
58
CSP. Eskom has completed a prefeasibility assessment of the proposed CSP project. However, there
is a need to undertake a comparison of its assessment to international best practices which is proposed
to be financed by this component. The outcomes of this assessment will be used to advise Eskom on
the way forward in terms of project design. Based on the recommendation of this assessment, the
component will also support Eskom in undertaking the preparation of a financial review and bidding
documents for the Upington CSP. An international advisory panel to support Eskom in the
implementation of the Upington CSP is also envisaged to be financed under the component. In
addition, this component will provide technical, financial and legal advisory services to Eskom to
develop domestic or cross-border renewable projects.
C.
Fiduciary
Procurement
210.
Procurement activities will be carried out by Eskom Holdings Limited (Eskom). Eskom is a
Public Company with a single shareholder, the Government of the Republic of South Africa,
represented by the Minister of Public Enterprises.
Eskom Procurement Capacity and Controls
211.
Eskom has a well-organized procurement system, with qualified and capable personnel.
Organization of the procurement function comprises separate arms for policy, strategic sourcing such
as bulk procurement of stock items, and capital procurement. Eskom’s procurement process is
governed by Eskom’s policies and procedures and the country’s legal framework as regards
procurement and fraud and corruption.
212.
Eskom’s commercial activities are governed by the Public Finance Management Act (PFMA)
which stipulates that an organization such as Eskom should have in place “an appropriate procurement
and provisioning system which is fair, equitable, transparent, competitive and cost-effective.” In
addition, a governance structure is in place that allows for a proactive, in-process audit and assurance
framework to be implemented with the objective of providing assurance to the governance structures
that the transaction under review is in accordance with PFMA. In addition to the PFMA, Eskom is
mandated to comply with legislation aimed at preventing fraud and corruption, public disclosure as
well as Black Empowerment.75 Eskom’s policies and procedures are consistent with this legislation. In
addition, an anti-corruption cell is managed by Eskom which refers any wrongdoing cases to GoSA
agencies in charge of ensuring fraud-free procurement by public agencies.
213.
Bid evaluation is conducted by independent evaluation panels, headed by a senior manager.
Four separate panels, one each for commercial, financial capability, ASGI-SA and technical
compliance, conduct the evaluation. A panel may call on specialized staff or independent consultants
for advice on specific aspects as and when required. Evaluation is conducted under strict
confidentiality, at premises specifically provided for the purpose, with restricted entry and no external
communication facilities. Internal audits are conducted for procurement above R300,000,000 (about
US$37,500,000) and external audits are conducted for procurement exceeding R750 million (about
US$100 million) prior to contract approval. The bid evaluation report is approved by the tender
committee at the relevant level. Complaints on the procurement process are addressed by the general
manager of the Enterprises division, Commercial department, and reviewed by the general manager of
the legal division. In the event that the supplier is not satisfied with the response, he has the right to
75
In addition to the PFMA, Eskom also is mandated to comply with the following legislation: Promotion of Access to
Information Act, No. 2 of 2000; Prevention and Combating of Corrupt Activities Act No. 12 of 2004; Preferential
Procurement Policy Framework Act No. 5 of 2000; Promotion of Administrative Justice Act No. 3 of 2000; Broad Based
Black Economic Empowerment Act No. 53 of 2003 (BBBEE); and The Construction Industry Development Board (CIDB)
Act 38 for 2000.
59
escalate the complaint via the legal process. For example, the Promotion of Administrative Justice Act
3 of 2003 grants persons materially adversely affected by “administrative action” the right to be given
written reasons by the administrator for the action in question. An anticorruption department is also
managed by Eskom, and besides its own investigation, it refers any transgression to GoSA agencies in
charge of ensuring fraud-free procurements by public agencies.
214.
The project includes implementation of three distinct components by Eskom. For Component
A, about U$1.766 billion of IBRD financing (see Table 13 and Table 14) would finance contracts
that have already been procured or whose procurement is close to completion, following Eskom and
GoSA policies and procedures and South Africa’s legal framework. US$593.03 million of IBRD Loan
(see Table 15) for Component A would finance new procurement that would follow IBRD policies
and procedures. The justification for the former is the lack of other funding for the Medupi Power
Plant and the dire consequences for South Africa and the region if the power plant were delayed or not
constructed. The situation the region faces is unprecedented and thus calls for an unprecedented
approach to address it. These issues have been explained earlier in the Rationale for Bank
involvement in the project.
Procurement under Component A (Medupi Power Plant, excluding Transmission Lines):
215.
The procurement action for the Medupi Power Plant was initiated in late-2005. At that time
Eskom and the Government expected Eskom to fund the program through a combination of internal
cash generation and commercial debt, which Eskom could normally have raised on the market with its
strong credit rating and GoSA support. They had no intention of seeking financing from the World
Bank or other multilateral agencies, and therefore had no reason to follow other procurement
guidelines and procedures but their own. The situation changed when a combination of a slower-thanexpected tariff progression and the global financial crises resulted in major funding shortfalls. The
GoSA and Eskom approached the AfDB76, IBRD and bilaterals, among others, to help bridge the
financing gap that emerged after having initiated all, or as of the present, having virtually completed
all procurement for the Medupi Power Plant. Contracts, comprising about 80 percent of the plant
value, have been awarded. Remaining contracts are expected to be awarded and signed during the next
few months. The current situation that the GoSA and Eskom are facing is unprecedented; IBRD
support has been requested for a utility/corporation midway though a large and nationally (and
regionally) critical project and the Bank has had no previous engagement in the country for major
investment lending.
216.
The Medupi Power Plant comprises various supply & install and construction contracts that
are being undertaken by Eskom as the employer for a cumulative value of US$9.999 billion, including
about US$765 million of contingencies. Eskom has requested the Bank to finance contracts that
amount to US$2.359 billion (excluding contingencies).
217.
Invitations to bid for all contracts were internationally advertised and sent to relevant
embassies in South Africa. For boilers and turbines, all major manufacturers were approached
individually along with domestic advertisements. The procurement process and contract award have
gone through stringent pre- and post-review audits by Eskom’s internal and external auditors.
218.
Table 13 provides an overview of the contracts (about US$7,437.40 million) that have already
been awarded.
76
AfDB’s Board approved the loan of US$2.63 billion equivalent on November 25, 2009. AfDB’s loan will finance some of
the already committed and procured contracts for Medupi Power plant.
60
Table 13: Medupi Power Plant – Supply & Install and Construction Contracts Already Awarded,
excluding additional contingencies
Name of the Contract
Amount (US$ Millions)
Proposed to be Financed by IBRD, of which
Coal Overland Conveyor
LP Services
Water Treatment plant
Chimney & Silos
Main Civils
Electrical Power Installation
Medium Voltage Switch Gear
Coal Stockyard Equipment
Dust Handling and Conditioning
Other Contracts not financed by IBRD
Total
1,383.72
28.88
155.93
105.47
118.02
599.24
127.18
39.61
Amount of proposed
IBRD financing
(US $ Millions)
1,383.72
28.88
155.93
105.47
118.02
599.24
127.18
39.61
130.90
130.90
78.49
6,053.68
7,437.40
78.49
1,383.72
219.
Procurement processes for the following contracts worth about US$382.65 million (or about
3.8 percent of the total value of the construction costs) which are proposed to be financed by IBRD.
Bids have been received; most of them are under evaluation or in the process of being finalized for
award. Table 14 below provides an overview of these contracts.
Table 14: Medupi Power Plant – Supply & Install and Construction Contracts in Advanced Stages of
Procurement, excluding additional contingencies
Name of the Contract
Proposed to be Financed by IBRD, of which
Low Voltage Switch Gear
Ash Dump Equipment and Ash Overland
Terrace Coal and Ash System
Uninterrupted Power Supply
Water Reservoirs
Total
Amount (US$ Millions)
Amount of proposed
IBRD financing
80.95
115.72
138.11
20.49
27.38
382.65
80.95
115.72
138.11
20.49
27.38
382.65
220.
As the GoSA and Eskom have requested the Bank to finance contracts which have not been
procured using the Bank’s Procurement Guidelines, the Bank has undertaken: (a) independent review
and/or due diligence at the aggregate level to establish that the overall procurement meets global
industry standards and cost parameters; (b) due diligence at the contract level to ensure that all
contracts financed by the Bank fully comply with Eskom procedures; and (c) there are no sanctioned
firms involved in the Medupi Power Plant contracts proposed to be financed by the Bank (see details
below for the current status of these assessments).
221.
Review at the Aggregate Level: The review was carried out by Nexant Inc. of USA, a San
Francisco based engineering consultancy firm. Nexant was commissioned to establish whether the
overall procurement process for the Medupi Power Plant met general principles of industry-wide
standards of economy, efficiency and transparency for this scale and timing of procurement. In so
doing, the Consultant was requested to benchmark the costs of the procurement of the plant (at an
aggregate level) for similar-size supercritical coal-fired power plants in the world. The following
paragraph provides a summary of Nexant’s analysis.
222.
Nexant has opined that although the procurement processes have been drawn out, they have
proved to be fair, transparent, and in compliance with the existing laws of South Africa. Nexant also
indicated that during the tendering period, the international market for 800-MWe boilers was
61
essentially sold-out. In addition, site location at the tip of Africa, along with the fact Eskom had not
been active in the international market for large power plant equipment since 1989, negatively
impacted Eskom’s position as a serious buyer in the large equipment market. This notion is also
corroborated by procurement carried out under Bank financed projects over the last few years, where
energy projects have not generated substantial participation from international suppliers because of
commitments in developed parts of the world (which is a preferred market for suppliers).
223.
Nexant has opined that the total base project cost for the Medupi Power Plant is comparable to
the US market and is on the low end of the EU market (without the FGD). However, Eskom’s costs
are higher77 when compared to plants being constructed in India and China – largely based on East
Asian and Indian suppliers.78 Nexant also noted that such data is mostly based on domestic supply of
plant equipment.
224.
Based on Nexant’s observation of large power-plant developments during 2005-2008, the
availability of (a) production capacity; (b) commodities such as specific types of high-strength steel;
and (c) resources and skills including labor, commercial, financial and technical (engineering) was
globally under pressure. In Nexant’s opinion, Eskom’s tendering experience for the supply of the six
boiler and steam turbine generator units for the Medupi project reflects the very competitive
worldwide power plant equipment and components market that existed from 2005 through 2008 for
major equipment procurement by Eskom.
225.
Review at the Contract Level: The Bank commissioned an independent Bank retiree consultant
(ex-chair of the OPRC) review to support Bank Procurement Specialists in carrying out due diligence
and to ensure that the procurement process undertaken for each of the contracts proposed to be
financed by the Bank has followed Eskom/GoSA policies and procedures. The review of the
procurement processes, which has been completed has concluded that the procurement process
followed by Eskom, although not in full compliance with the Bank’s Procurement Guidelines, was
transparent, focused on economy and efficiency, gave the same opportunity to several bidders from
developed and developing countries and included procedures to encourage development of domestic
contractors.
226.
The review of the procurement processes revealed areas of divergence between the Bank’s
procurement procedures and Eskom’s procedures. Some of the key deviations include: (a) Eskom uses
own bidding documents with modified FIDIC conditions of contract, which inter alia do not have
fraud and corruption and right to audit clauses as required by the Bank; (b) bids are opened in public,
prices are not read out; (c) negotiations conducted with the lowest evaluated bidder; (d) merit point
system is used to evaluate bids for works; (e) Accelerated Shared Growth Initiative of South Africa
(ASGI-SA)79 and Competitive Supplier Development Program (CSDP) are taken into consideration in
the evaluation of bids; (g) use of registration of bidders grading firms based on the capability criteria
as a condition of contract award; and (h) parent company guarantees are required.
227.
The review of Eskom’s procurement procedures, including the analysis of the deviations from
Bank procedures (see Annex 8 for details), has concluded that these procedures were well established
and transparent.
77
Estimated by up to 40 percent on some contracts.
The increases in construction costs particularly during the 2004-2008 time period are still being experienced by proposed
coal-fired power plants due, in large part, to a significant increase in the worldwide demand for power-plant design and
construction resources, commodities and equipment. The limited capacity of EPC firms and equipment manufacturers also
has contributed to rising power-plant construction costs. This has meant fewer bidders for work, higher prices, earlier
payment schedules and longer delivery times. The demand for and cost of both on-site construction labor and skilled
manufacturing labor also have escalated significantly in recent years.
79
ASGI-SA preference is given to persons disadvantaged by unfair discrimination.
78
62
228.
Fraud and Corruption (F&C) and Audit Rights: The contractual clauses (in the modified
FIDIC documents that Eskom is using for Medupi procurement) did not provide the Bank exactly the
same rights with respect to Fraud and Corruption as the Standard Bidding Documents (SBDs) of the
Bank. To this extent, Eskom has agreed to incorporate such rights (for the Bank) in the contracts
awarded for the Medupi Power Plant and proposed to be financed by the Bank. Eskom has begun the
process of inclusion of these clauses (consistent with Bank requirements on Fraud and Corruption and
Audit Rights) in the contracts already awarded or currently being finalized. The Bank will not finance
any contracts which do not include the Bank’s Fraud and Corruption related clauses.
229.
It is not possible to obtain Audit Rights for the bidders who were not selected as they do not
have any obligations to Eskom. The Bank, therefore, will not have Audit Rights on such bidders. 80 To
this extent, the Bank has reviewed the legal framework for F&C in South Africa and is comfortable
with the rights that Eskom and the GoSA have to pursue any F&C allegations or procurement-related
complaints.81 82 However, as a measure of abundant caution, the Bank has received an assurance from
the GoSA and Eskom to cooperate with the Bank, based on South African law, in case the Bank is
required to pursue F&C allegations or suspicion with regard to the procurement process of any of the
contracts proposed for Bank financing. GoSA and Eskom have committed themselves to ensuring
their full support to the Bank to investigate any issues as and if they arise. A legal covenant to this
effect has been negotiated in the IBRD Guarantee and the IBRD Loan Agreement. Moreover, in the
event the Bank finds any misrepresentation of information from Eskom it would have the right to
cancel the loan disbursed for the contract.
230.
Eskom has provided the Bank with a list of Contractors and Subcontractors for ten contracts
that IBRD will finance for the Medupi Power Plant. The Bank will ensure that the firm chosen is not
and was not at time of award or contract signing on: (a) the Bank’s Debarred List of firms; or (b)
Temporarily Suspended List of firms. Contracts awarded to firms debarred or suspended by the Bank
(or those which include debarred or temporarily suspended subcontractors/subsuppliers) will not be
eligible for the Bank financing. For the purposes of implementation of Bank-financed contracts,
Eskom has established a procedure of checking new subcontractors/subsuppliers that may be proposed
by the contractors to ensure that Eskom does not approve a debarred or temporarily suspended firm as
a new subcontractor or subsupplier.
231.
Conclusion: Based on the satisfactory completion of the above-mentioned review and due
diligence including the benchmarking and continuing compliance check to ensure that procurement of
the contracts has met general principles of industry-wide standards of economy, efficiency and
transparency for this scale and timing of the procurement, verification that the contractors and
subcontractors that were awarded the contracts were not debarred or suspended at the time of contract
award or signing, and the incorporation of F&C and Audit Rights provisions in the contracts, specific
Board approval is sought to finance the contracts for the Medupi Power Plant already awarded by
Eskom under Component A using Eskom/GoSA procedures. The one-time exception is being sought
for application of the Bank’s Procurement Guidelines (not Consultant Guidelines), only for the
Medupi Power Plant contracts (excluding the transmission lines) under Component A of the proposed
project.
232.
The current situation that GoSA and Eskom is facing is unprecedented; IBRD support has
been requested for a utility/corporate midway through a large, and nationally (and regionally) critical
project and the Bank has had no previous engagement in the country for major investment lending.
Alternatives to seeking the proposed one-time exception are difficult. The alternative would be to seek
80
These Audit Rights to permit the Bank to inspect their accounts and other records relating to the bid submission arise out of
provisions in the Standard Bidding Documents. Also refer to Paragraph 1.14(e) of Procurement Guidelines.
81
Eskom does not register procurement process related complaints and provides such complaints to other GoSA agencies for
further action.
82
In this connection, a legal opinion from Eskom’s independent counsel is a condition of effectiveness of the IBRD Loan.
63
rebidding of the identified and already procured contracts, which is not feasible; any rebidding of such
contracts would result in major contractual consequences (penalties, etc.). Rebidding of contracts
which are yet to be awarded has serious consequences as well. Despite major contracts being awarded,
the plant would not be able to reach commissioning without the goods and equipment yet to be
awarded and therefore rebidding would result in a delay of at least 2 to 3 years in the commissioning
schedule for the project. The Medupi Power Plant’s generating capacity, when commissioned, will
account for nearly 12.5 percent of the current generation capacity in South Africa. If full
commissioning, now expected in August 2015, is delayed to 2018, it will have serious impacts on the
South African economy and that of the subregion.
Procurements under Components A (Medupi related Transmission Lines), B and C
233.
Procurement processes for the remaining Medupi contracts worth about US$593.03 million (or
about 5.9 percent of the total value of the construction costs) have not yet begun. Table 15 below
provides an overview of these contracts.
Table 15: Medupi Power Plant – Supply & Install and Construction Contracts, where Procurement
Process has not begun, excluding additional contingencies
Name of the Contract
Proposed to be Financed by IBRD, of which
Ash Dump and Dams
Buildings
Associated Transmission Lines
Total
Amount (US$ Millions)
Amount of proposed
IBRD financing
221.61
129.33
242.09
593.03
221.61
129.33
242.09
593.03
234.
Additional Procurement for the associated transmission lines under Component A, and for
contracts under Components B and C of the proposed project, is yet to be carried out. This
procurement will be carried out in accordance with the World Bank’s “Guidelines: Procurement under
IBRD Loans and IDA Credits” dated May 2004, revised October 2006; and “Guidelines: Selection and
Employment of Consultants by World Bank Borrowers” dated May 2004, revised October 2006; and
the provisions stipulated in the Legal Agreement.
235.
Eskom will carry out procurement using the Bank’s Standard Bidding Documents for all ICB
and the Bank’s Standard Request for Proposals for selection of consultants.
236.
The Bank has reviewed a set of bidding documents prepared by Eskom at the Bank’s request
which included the above methodology and found them equivalent to the Bank’s SBDs with changes
as permitted by the Procurement Guidelines (paragraph 2.12). However, a change in contract terms
post-award that provides an incentive through availability of more favorable contract payment terms,
which would not be taken into account in the evaluation, but which potentially could affect equal
opportunity of some bidders (local or foreign) is not contemplated in the Bank’s Procurement
Guidelines. It is the Bank’s assessment that the risk of occurrence of such a scenario is low for the
type and size of contract packages which the future procurement would comprise.
237.
Based on the above and the country-specific considerations noted previously, Board approval
is being sought for the inclusion of the ASGI-SA related provisions as proposed by Eskom. The
approved solution would be used in the procurement of goods, works, and supply & installation
contracts.
Procurement Risk Assessment
238.
The risks concerning the procurement already carried out are identified in Annex 8.
64
239.
The overall project risk for procurement is Substantial and the residual risk after
consideration of the corrective measures is Substantial. The Bank will continue to closely monitor
implementation of the corrective measures, which will mitigate the identified risks, and the residual
risk may be adjusted during project implementation.
Financial Management
240.
A financial management assessment of Eskom Holdings shows strong financial management
capacity in accordance with applicable legal frameworks and Eskom’s policies and procedures.
241.
For FM implementation of the project, Eskom will use its existing, acceptable SAP-based FM
system with appropriate oversight by DPE and the Board. This is based on the capability of the system
to produce reliable and regular unaudited financial reports (IFRs) and other financial reports.
242.
Eskom’s Directors are responsible for the preparation and fair presentation of the financial
statements and their explicit legal responsibility includes the design, implementation and maintenance
of internal controls relevant to the preparation and fair presentation of financial statements that are free
from material misstatement, whether due to fraud or error. The Board has delegated this function to the
Chief Finance Officer. The internal controls system is also subject to robust internal audits governed
independently by an Audit Committee (five independent non-executive Directors). There is also a Risk
Management Committee, comprising four independent non-executive directors and the finance
director. It ensures that Eskom’s risk management strategies and processes are aligned with best
practices. The Audit Committee chairman also sits on the Risk Management Committee to ensure that
common issues are addressed adequately. The Board also ensures that an integrated crime-prevention
plan is implemented to minimize exposure to criminal acts, particularly fraud. A Security Risk
Management Department addresses these threats. Its work covers crime prevention, detection,
response and investigation. Where serious fraud, corruption and irregularities are suspected, forensic
investigations (a division of Security Risk Management) establishes the facts to enable management to
deal appropriately with the matter and prevent a recurrence.
243.
Eskom is a public company, fully owned by the Government. Its financial affairs and
disclosures are governed by its own Act, read together with the PFMA, the Companies Act, its
financial policies and International Financial Reporting Standards – with all of which it fully complies
with. For the financial year ended 31 March 2009 it was jointly audited by KPMG Inc and
SizweNtsaluba VSP, who concluded that the financial statements present fairly, in all material
respects, the financial position of the company and of the group as of 31 March 2009 and their
financial performance and their cash flows for the year then ended in accordance with International
Financial Reporting Standards, and in the manner required by the Public PFMA 1 of 1999, and the
Companies Act of South Africa.
244.
Eskom’s auditing arrangements are considered acceptable. Eskom’s annual audit report
together with a management letter as it pertains to the project and management’s response are to be
submitted to the Bank within six months of the end of each reporting period, that is, by September 30,
of each year.
245.
Eskom went through a short period of leadership uncertainty in late October 2009, when both
the Chairman and Chief Executive Office (CEO) resigned. The responsible Minister (for Public
Enterprises) took immediate action to normalize the situation by appointing one of the Board members
as acting Chairman/CEO. Under his leadership, Eskom has made progress in dealing with issues
related to its MYPD 2 tariff application and continues to address Eskom's financing problem over the
short and longer term, including postponement of some investment, and bringing in private equity for
the coal-fired power plant. The Minister also took immediate steps to appoint a new CEO. As of mid
February 2010, a short-list of candidates had been identified and the selection process was at an
advanced stage.
65
246.
The Board of Directors has also implemented a strong corporate governance framework, and
Eskom’s systems and processes are regularly reviewed to ensure that compliance is monitored in this
regard. In addition, Eskom also adopted best corporate governance practices embodied in the King
Report on Corporate Governance for South Africa – 2002 (King II) and the Protocol on Corporate
Governance in the Public Sector – 2002. Eskom has a unitary board structure with 13 non-executive
directors and two executive directors. All of the non-executive directors are independent directors,
appointed by the shareholder, drawn from diverse backgrounds (local and international) and reflecting
South Africa’s demographics. They bring a wide range of experience and professional skills to the
board. In addition, a number of respected external individuals have been appointed to Board
committees, bringing additional experience to the table.
247.
Eskom’s articles of association stipulate that the shareholder will, after consulting the board,
appoint a chairman, chief executive and non-executive directors. The remaining executive directors are
appointed by the Board after obtaining shareholder approval. In compliance with good corporate
governance the composition of the Board is also reviewed on a regular basis and rotation of directors
occur at regular intervals. The term of office of non-executive directors is a maximum of three years.
Unless otherwise called for, regular Board meetings are scheduled annually in advance.
248.
Eskom will maintain a US Dollar denominated segregated Designated Account (DA) in a
commercial bank for the implementation of the Bank-financed components of the project.
Disbursements by the Bank into this account will be based on the quarterly Interim Unaudited
Financial Report (IFR) and withdrawal applications prepared and submitted by Eskom to the Bank.
The submission will be required within 45 days of the end of each reporting period. Upon
effectiveness of the loan agreement and submission of a withdrawal application, the Bank will initially
disburse an amount equivalent to six months estimated project expenditures into the DA. Subsequent
disbursements to the DA will be based on six- monthly estimated expenditure, taking into account the
balance in the DA at the end of each quarterly reporting period and reporting on the use of the
advances previously made. Eskom will also have the option of using: (i) the Direct Payment
disbursement method involving direct payment from the Loan Account on behalf of Eskom to
suppliers of goods and services that have a value above the Minimum Application Size (US$75 million
equivalent); (ii) the Reimbursement disbursement method, whereby Eskom will be reimbursed for
expenditures which it has prefinanced from its own resources and submits withdrawal application for
reimbursement above the Minimum Application Size (US$75 million equivalent); and (iii) the Special
Commitment method whereby the Bank at the request of Eskom, will issue special commitments to
suppliers of goods under the Bank financed components above the Minimum Application Size (US$75
million equivalent).
249.
The FM arrangements meet the Bank’s minimum requirements under OP/BP 10.02 Financial
Management. (See “Annex 7- Financial Management” for details.)
D.
Social
250.
Land Acquisition and Resettlement. South African legal requirements for resettlement and
compensation are broadly consistent with OP 4.12 (Involuntary Resettlement) as well as the
Objectives and Operational Principles of OP 4.00 (Use of Borrower Systems to Address
Environmental and Social Safeguard Issues in Bank-Supported Projects) Table A1, especially in the
context of transparency in consultations with directly affected people, fairness of compensation, the
widely-known availability of appeal mechanisms, and, particularly for the poor, a requirement for
significant improvement in living quarters and opportunities for betterment of livelihood (economic
rehabilitation).
251.
South African law goes beyond market-value compensation, to include all costs needed for the
affected landowner to re-establish an economic livelihood, including losses incurred during the
66
transition period. South African law also guarantees that all people living on an acquired property,
such as tenants, employees, or even squatters, are entitled to resettlement and assistance to improve
their economic well-being.
252.
One key area in which South African legislation, and Eskom’s practice to date, differ from
Bank practice is the absence of a requirement for preparation and public disclosure of a stand-alone
Resettlement Action Plan (or Resettlement Policy Framework) prior to resettlement. It is important to
note that the difference is not in the substance of the process, but that in South Africa there is no
requirement to systematically document and make public how resettlement will occur, what rights and
benefits are available, and what grievance and appeal procedures are available. This gap between the
GoSA and Bank resettlement process has been filled for EISP through two actions by Eskom. On
October 7, 2009, Eskom disclosed two documents that together constitute a Resettlement Policy
Framework for Components B and C: the corporate resettlement policy and procedure, which clearly
explains the principles and procedures Eskom follows in acquiring land and other assets,83 and an
overview of the potential land acquisition and resettlement for the components, which gives estimated
land requirements and numbers of affected persons and explains the process Eskom will follow in
addressing involuntary resettlement, land acquisition, and livelihood restoration (rehabilitation),
including preparation and disclosure of RAPs for any future resettlement.84 In addition, Eskom will
arrange for independent audits of any resettlement already carried out for EISP project components
(i.e., some of the transmission lines for the Medupi project, and acquisition of the right-of-way for the
Majuba rail spur).
253.
Involuntary resettlement issues are virtually non-existent at the Medupi Power Plant (which is
under construction). Eskom purchased from willing sellers two large game farms for the Medupi site;
the directly affected parties were the two sellers, one of which was a corporation. The other farm
owner lived in town and owns another farm; one full-time worker had lived on the farm purchased for
the project site for about one year before the purchase and has been relocated to the other property at
the expense of the same owner. The extent of resettlement necessary for transmission lines to connect
the Medupi Plant to the grid is not known because the exact alignment of the lines has not been
finalized with the various property owners from whom the right-of-way will be acquired. In deciding
on the alignment, Eskom tries to avoid resettlement altogether, and the number of houses that will
need to be relocated, if any, is likely to be small. Eskom compensates landowners for the right-of-way
on the basis of either 100 percent of market value for the land or 100 percent of the financial loss.
Eskom either pays for or replaces trees or structures such as windmills and water tanks that need to be
demolished.
254.
Eskom has nearly completed the acquisition of the 16 km2 needed for the WPP. The land is
being purchased from three farm owners on a willing-buyer, willing-seller basis. No resettlement will
result from the development of the WPP or acquisition of the right-of-way for its 132-kV transmission
line. Eskom is negotiating the purchase of land for the Upington CSP from a single farm owner. The
CSP itself will occupy 4 km2, and the right-of-way for the 132-kV transmission line to connect to the
grid is located on the same farm property. There will be no resettlement, and farming activities (mainly
cattle grazing) will not be significantly affected.
255.
The route for the Majuba Rail Project line is 67 km long and crosses the lands of 43 separate
farm owners. Eskom has acquired the land for the entire route through a combination of rights-of-way
and outright purchases – a total of approximately 330 ha. Twenty-one households with 152 residents
are being resettled, mainly because of potential noise impacts that cannot be otherwise mitigated. On83
“Procedure for the Involuntary Resettlement of Legal and Illegal Occupants on or from Eskom-procured Land” (July
2009).
84
“Status and Process of Land Acquisition and Resettlement for Eskom’s Concentrating Solar Plant (CSP), Wind Energy
Facility, Majuba Railway and Transmission Projects” (October 2009).
67
farm relocation has been agreed in the case of 16 of those households. Land has been acquired for the
other five families.
256.
A review of Eskom’s land acquisition and resettlement practices indicates that they fully meet
the requirements of South African legislation.
257.
Corporate Social Responsibility. Eskom endeavors to enhance the social and economic
benefits of individual projects and to minimize adverse indirect impacts. For example, at Lephalale,
the municipality in which the Medupi Power Plant is located, Eskom operates a training center to
prepare local residents for employment at the site. Eskom maintains information centers for its various
projects, and the names and qualifications of citizens who come to the centers looking for employment
or business opportunities are registered in a database that is provided to contractors. Eskom is also
assisting the local government at Lephalale to upgrade wastewater treatment systems and other
municipal infrastructure that is being overloaded in part because of the construction-related increase in
local population. In the case of the Majuba Rail Project, Eskom will be directing its contractors to
source and house their workforces in the local communities, where there is excess housing already
available. To prevent hardship for the approximately 100 small trucking companies that currently haul
coal to Majuba, Eskom will redeploy some trucks to short haul (from mine to rail) and will phase out
the remainder over a 10-year period guaranteeing certain tonnage in the meantime.
258.
At the corporate level, Eskom has established the Eskom Development Foundation, which has
as its objectives “providing support to economic and social projects through the vigorous promotion of
support to registered small, medium and micro enterprises (SMMEs), particularly in communities
where Eskom implements its capital expansion projects, as well as enhancing the quality of life in
communities by supporting social projects.”
259.
HIV/AIDS. Eskom became concerned about the potential impact of HIV/AIDS on its
workforce and operations in 1988. It commissioned an HIV/AIDS impact assessment in the mid-1990s
and established a cost center for HIV/AIDS awareness and response in 1996. The Company has been a
member of the Global Business Coalition on HIV/AIDS, Tuberculosis and Malaria since 2001 and, in
2007, received a “Best in Business Action” award from that organization for demonstrating best
practices in HIV/AIDS response. Eskom’s HIV/AIDS program consists of three key elements:



Prevention and Awareness, using proven methods including trained peer educators (over 1,200
to date) and theater to reach employees at all sites, covering human rights and HIV/AIDS care
as well as HIV prevention. All Eskom staff are required to take awareness training as a
requirement in their performance contracts. Condoms are available through dispensers in most
Company toilet facilities. The company provides treatment for sexually transmitted infections
(STIs) free of charge through its clinics. Sessions run by people living with HIV/AIDS help
address stigma associated with the virus.
Voluntary Counseling and Testing (VCT), with Eskom paying for the first test, which can be
done through any agency approved by the company.
Care and support, including psychological support from counselors, access to antiretroviral
therapy (ARVs) under the Company’s medical aid insurance scheme (which covers all
employees and their immediate families) through approved HIV clinicians, and monitoring of
TB treatment at the Company’s own clinics. 260.
Eskom held an “HIV/AIDS Awareness Day” at its Matimba Power Station on December 1,
2009, to which Company and contractor personnel working at the Medupi construction site were
invited. Eskom also takes its programs to community centers and schools in the vicinity of its
facilities.
68
E.
Environment
261.
According to a review conducted by the Bank, South Africa’s legal, regulatory and
institutional framework is nearly fully equivalent to the World Bank’s corresponding safeguard
policies for Environmental Assessment, Natural Habitats and Physical Cultural Resources and is
consistent with South Africa’s commitments to its international environmental agreements with respect
to these safeguards.85 Additional review conducted as part of the identification mission confirmed the
equivalency as well as the conclusion that Eskom and the environmental regulatory agencies have the
institutional capacity, requisite procedures and track record to meet the acceptability criteria of OP
4.00 with respect to all applicable Bank safeguard policies. Accordingly, a Safeguards Diagnostic
Review (SDR) was prepared for the Project, as described later in this section. A review of the
environmental and social safeguards for the Medupi Power Plant and other project components
showed that the South African processes followed were consistent with World Bank requirements.
262.
Structure and institutional capacity: Eskom has developed substantial capacity to conduct EA,
through independent consultants (as required by the EIA regulations); to prepare and implement
EMPs; and to pro-actively engage the affected public and NGOs in informed consultation through
transparent public disclosure of projects and alternative siting and mitigation strategies. An Executive
Management Subcommittee on Sustainability and Safety guides Eskom’s strategy on sustainability and
environmental and occupational health and safety. At the technical level, the Subcommittee is
supported by the Environmental Liaison Committee, which includes all environmental managers and
representatives from the generation, transmission, distribution, audit, legal and research units. Overall,
there are approximately 120 environmental and social professionals working at Eskom out of a total of
35,400 employees.
263.
The DoEA (formerly DEAT) is the lead agency for all issues involving environmental
management, including EA; drafting of legislation and issuance of regulations affecting the
environment; and monitoring environmental impacts, emissions and effluents from point sources,
including electrical generation and transmission facilities. At the end of December 2009, DoEA had
1,874 authorized staff positions with an 18 percent vacancy rate. DoEA is organized into six integrated
departmental programs, each led by a separate organizational unit, or branch, and supported by various
public entities and statutory bodies: The Environmental Quality and Protection (EQP) unit is mandated
to protect and improve the quality and safety of the environment, including air, water and soils. Within
EQP the Chief Directorate of Environmental Impact Management is responsible for all aspects of EIA
and is divided into separate Directorates for Environmental Impact Assessment, Environmental Impact
Processing and Environmental Impact Management. As of end December 2009, EQP had 213
authorized staff positions, 56 of which were vacant, and 22 additional contract employees.
264.
Environmental Assessment: The Bank has so far reviewed the EIAs as well as construction
stage and early draft operational stage Environmental and Social Management Plans for the Medupi
plant and associated transmission lines, which represent the largest financing needs, and the EIAs for
the Sere WPP, the Upington CSP, and the Majuba Rail Project. Bank safeguards specialists have
visited the sites for these facilities. With respect to Medupi, the main concern relates to the
management of air quality impacts and related health risks of sulfur dioxide (SO2) emissions. The
baseline SO2 concentrations in the area are affected primarily by the existing Matimba Power Station,
and use of coal in home heating systems in the nearby town of Marapong. Prevailing winds are from
the northeast all year, and the highest SO2 levels occur in the sparsely populated game farm area to the
southwest. The GoSA interim ambient standards did not include a one-hour limit for SO2, but in the
EIA analysis a one-hour limit of 350µg/Nm3 was applied, based on European Commission standards.
85
South Africa, Safeguard Diagnostic Review for South Africa: Development, Empowerment and Conservation in the
iSimangaliso Wetland Park and Surrounding Region (iSimangaliso), Consultation Draft, November 2008 (SDR).
69
To put this in perspective, California has defined a one-hour threshold risk level of 660 µg/Nm3 for atrisk individuals.
265.
Sampling data from various periods between 1991 and 2005 show that these limits were
exceeded relatively infrequently even at monitoring stations directly downwind and within 4 km of the
Matimba plant. The percentage of the hours sampled that exceeded the EC 1-hour standard of 350
µg/Nm3 in sampling periods between 1989 and 2004 ranged from 0.02 to 0.23. The daily average
of125 µg/Nm3 was exceeded only three times and at only one station, 3 km immediately west of the
Matimba plant. There was consistent compliance with the annual average in all sampling programs.
An intensive 10-month Eskom sampling campaign in 2004-5 at 10 stations surrounding Matimba
included one station 8 km downwind of the plant, at which the EC hourly SO2 limit was exceeded only
once and the daily average was not exceeded at all. Annual averages ranged from 3 to 11µg/Nm3 at the
ten stations, not even approaching the limit of 50.
266.
The EIA concludes that “little potential exists for… health risks due to sulfur dioxide levels”
in the high-exposure areas downwind of the plant. The most populated locality that is affected is the
town of Marapong (population 17,000) which is near Matimba but to the northeast, hence normally
upwind. There, although ambient concentrations are lower and limits are exceeded less frequently than
at downwind stations, the health risk rises because a population of 17,000 will include a significant
number of individuals with respiratory conditions. The report points out that the evaluation of risk in
Marapong is based on short-term exceedence of health thresholds occurring on average only four times
per year. Eskom established a continuous monitoring station in Marapong in January 2008, and
quarterly monitoring reports show that through December 2009, the 1-hour limit for SO2 in the thenproposed (and since adopted) new DoEA standards was exceeded five times during those two years.
Two of the exceedences occurred when the wind was from the northeast; the Matimba Plant could not
have been the source of the SO2 on those occasions.86
267.
Operation of the six units of the Medupi Power Plant without FGD was predicted to raise the
number of times the daily concentration limit is exceeded in the maximum impact area downwind to
33 times per year, and to more than double the size of that area. The EC hourly limit could be
exceeded 419 times in a year downwind. The additional area affected is likely to remain as sparsely
populated game farms, and the risk of health effects therefore remains low. At Marapong, the
dispersion model predicts exceedence of the EC hourly limit 35 times and of the daily limit 4 times per
year. These numbers continue to be relatively low because the wind blows only infrequently from the
southwest. The maximum 1-hour and 24-hour concentrations at Marapong are predicted to be 1,481
and 153µ/Nm3, respectively. The annual average is predicted to be 42.7µg/Nm3 in the high impact area
and 6.8µg/Nm3 at Marapong, both below the interim annual limit. The EIA concludes that installation
of FGD with at least 80 percent removal efficiency at Medupi would maintain the health risk potential
at the baseline condition – i.e., with Matimba only. Eskom is building Medupi to be FGD ready and
has made a commitment to install FGD with better than 90 percent removal efficiency, so that Medupi
will not cause the ambient SO2 standard to be exceeded. The understanding reached between Eskom
and the Bank on the schedule for installation is a covenant in the Loan Agreement (see Section III.F
above).
268.
On December 24, 2009, the Minister of Water and Environmental Affairs issued final ambient
air quality standards, to take effect immediately.87 Unlike the interim standards, the final ones are
expressed as a combination of limit values and frequencies of exceedence. For SO2 a 1-hour limit
value of 350µg/Nm3 has been introduced; the other limit values are unchanged. Consequently, the
conclusions and predictions in the EIA concerning exceedence of limits remain valid. The frequencies
86
Eskom Corporate and Services Division, “Marapong Air Quality Quarterly Report,” 2008 and 2009. Eight quarterly reports
were reviewed. No other ambient air quality limits were exceeded.
87
Government Gazette No. 32816, 24 December 2009.
70
of exceedence represent the maximum number of times a limit value can be exceeded at a given
sampling location in a calendar year without resulting in non-compliance with the standard: for SO2 it
is 526 times for the 10-minute standard, 88 times for hourly, 4 times for daily, and zero for the annual
average. If these exceedence frequencies had been in effect at the time the EIA was written, its
conclusions would have been that the baseline data showed virtually no instances of non-compliance
with any of the standards, and the SO2 concentrations predicted by the dispersion model would not
result in non-compliance in Marapong. Similarly, the five exceedences measured in Marapong over
2008-9 are well within the tolerance for the 1-hour standard, and the SO2 concentrations predicted by
the dispersion model would also not result in non-compliance there. However, the predicted numbers
of exceedences of the hourly and daily limits in the maximum impact area downwind of Medupi are
greater than the permissible frequencies of exceedence in the final standards. Although the risk for
human health effects remains low, because the downwind area is expected to remain sparsely
populated, the Bank believes that installation of FGD, as planned by Eskom and described below,
would be consistent with internationally recognized good practice.
269.
DoEA (then DEAT) took into account the baseline conditions and model predictions in its
environmental authorization for Medupi issued September 21, 2006, by setting the following
conditions:

Eskom must initiate a program for the continuous monitoring of ambient concentrations of
pollutants in the Marapong residential area as well as surrounding areas around the proposed
power station and existing Matimba Power Station. The program must also detail reporting
procedures including, among others, the submission of quarterly reports to the department.

Eskom shall install, commission and operate any required SO2 abatement measures that may
be necessary to ensure compliance with any applicable emission or ambient air quality
standards.

Notwithstanding the measures referred to [above],…should the monitoring…indicate noncompliance with ambient SO2 standards, Eskom shall install, commission and operate any
required SO2 abatement measures in respect of the Matimba Power Station as may be
necessary to ensure compliance with any applicable emission or ambient air quality standards.

Eskom must initiate a program of support for initiatives aimed at improving air quality in the
Marapong residential area. This program must be included in the construction EMP and
carried through to the operational EMP.
270.
DoEA is in addition considering designating the region around Medupi – the Waterberg
airshed – as a National Priority Area for Air Pollution Control. Normally this occurs when an airshed
is out of compliance, but in this case, the action would be proactive. DoEA’s objective is to avoid the
deterioration of ambient air quality that could otherwise occur if, as expected, there is further
residential and industrial development (besides Medupi) that would increase emissions of air
pollutants generally. This designation will result in expanded monitoring, more intensive scrutiny of
development proposals, and the likelihood that project developers will be required to install pollution
control equipment sufficient for compliance with ambient standards, not merely the applicable
emission standards. The expanded monitoring and more intensive scrutiny would also be relevant to
the SO2 abatement measures for both Medupi and Matimba power plants, as noted above regarding the
environmental authorization for Medupi.
271.
Eskom’s staged approach to FGD is consistent with the environmental authorization and in
fact anticipates the response to “any required SO2 abatement measures” by designing Medupi so that it
can be retrofitted with wet FGD equipment. Eskom proposes to install FDG on the Medupi units in a
sequential manner, as each operating unit undergoes its generation outage for major maintenance
(normally after six years of operation). This timetable, which is reflected in a legal covenant in the
71
Project Agreement with Eskom, is expected to begin in 2018 at the earliest and continue through 2021,
at which time Medupi will be fully equipped with FGD. The Bank recommends that Eskom install
FGD at Medupi as soon as it is technically and operationally feasible to do so, recognizing that a
necessary condition to beginning the installation is availability of additional water supply from the
DWA project described below. In the meantime, Eskom will operate Medupi beginning at
commissioning to comply with the proposed GoSA SO2 emission standards for an “existing” facility,
as approved by DoEA, which is also consistent with the approach to existing facilities as stated in the
Bank’s Environmental, Health and Safety Guidelines for Thermal Power Plants that went into effect in
December 2008. Should unhealthful SO2 concentrations develop in Marapong, the fact that they are
predicted to be of short duration makes possible a variety of measures to reduce or eliminate adverse
impacts on individuals at risk, some of which are as simple as warnings based on predictions of
southwest winds, and health advisories for at risk individuals to stay indoors. Eskom has already begun
a research program in Marapong to identify and explore possible initiatives; one example would be
supporting conversion of other air pollutant sources such as home heating systems to technology that
would have lower SO2 emissions.
272.
The three transmission lines for Medupi were initially not to be financed by the Bank but were
considered to be associated facilities for EIA purposes. However, they have subsequently been
included as one of the investments the project will support. The EIA for “Medupi Transmission
Integration” identifies visual and landscape changes, risk of bird collisions with cables, and
degradation of certain natural habitats as the most significant impacts of the transmission line that will
connect Medupi to the grid. The EIA proposes a preferred corridor to minimize these impacts and
recommends mitigation measures that reduce most of the impacts to “low”.
273.
No new coal mines will be developed to supply fuel to Medupi. The plant site is adjacent to
the Grootegeluk Colliery, an open-pit, back-cast mine operated since early 1981 by Exxaro and located
on the southern end of the vast Waterberg coal bed. Grootegeluk currently produces 18.6 million
metric tons of coal per year (M mt/yr), of which 15.3 M mt/yr of thermal coal is supplied to the
Matimba Power Plant. Grootegeluk will expand production in phases to meet the needs of Medupi –
an additional 14.6 M mt/yr of thermal coal when in full operation – under a long-term contract. As a
result, coal will be mined at an accelerated rate, but Grootegeluk’s reserves, 5,600 million tons within
the authorized area of mining operations, will be sufficient for the lifetimes of Matimba and Medupi.
In order to support the increased coal sales to Eskom, Exxaro will add two new coal processing
(beneficiation) units to the six already operating at the mine. Because neither any mining nor the
construction of the new processing units and associated coal stockyard will occur outside the permitted
boundaries of the mine operations, GoSA regulations do not require a full EIA and an environmental
authorization from DoEA.88 Instead, the company’s obligation under national environmental
legislation is to obtain approval of an amendment to its Environmental Management Program for
Grootegeluk from the Limpopo Department of Minerals and Energy (LDME).
274.
For this purpose, in 2006 the mine owner prepared an environmental document entitled
“Amendment to the Grootegeluk Mine Environmental Management Programme Report (EMPR):
Matimba Brownfields Expansion Project.” Scoping for this report was conducted with stakeholder
participation in March 2006, and the draft report was publicly disclosed for stakeholder consultations
in July 2006. LDME issued its approval for the amendment to the EMPR in 2007. The Bank has
reviewed the report and considers the assessment adequate for the expansion of mine production
within its already approved area of operations. The key concerns identified beyond the mine site
boundaries are increased water use, traffic and traffic hazards, possible exposures to dust on two
adjacent farms, and indirect effect of expanded employment such as pressure on local infrastructure
and housing due to a larger workforce, and elevated incidence of HIV/AIDS and other sexually
88
The Coal mine is owned by the private sector and has been in operation since 1980. The EIA for the mine was on the
Exxaro website until 2006, consistent with the South African requirements.
72
transmitted diseases associated with an influx of workers and job-seekers.
amendments to the EMPR address all of these impacts.
The recommended
275.
The Medupi Power Plant is being constructed with dry cooling in order to minimize its
demand for water. Water consumption will begin with the commissioning of the first generating unit
(expected in 2012), increasing gradually to 3 million cubic meters per year (M m3/yr) with three units
operating (in about 2014), then to 6 M m3/yr in full operation (about 2016 or 2017). Phased
installation of FGD over the period from 2018 to 2021 will gradually raise consumption to the
anticipated full volume, 12 M m3/yr. Expanding production at the Grootegeluk Mine to supply coal
for full operation at Medupi will entail use of approximately 2 M m3/yr of water beyond the mine’s
current allocation from Mokolo Dam. Medupi’s full operation and FGD water needs as well as the
additional needs of the mine will be met by DWA as it implements the first two phases of the MokoloCrocodile (West) Water Augmentation Project (MCWAP), which is an outgrowth of a Catchment
Management Strategy formulated by the South African Department of Water Affairs (DWA) in 2004,
to meet the 25-year planning horizon that anticipates high and growing demand for water for public
supply, irrigation and industrial use in the Lephalale-Steenbokpan corridor in which Medupi is located.
Sufficient water is available in the Mokolo Reservoir for the early operation of Medupi, by means of
re-allocation from other uses for which the present allocation is not fully utilized. There is already a
water transmission main, owned by Exxaro, operator of the Grootegeluk mine that conveys water from
Mokolo to the mine, the Matimba Plant, and Lephalale Municipality. A short extension is being built
from Matimba to Medupi as part of the Medupi construction project. A preliminary activity in
MCWAP is the “debottlenecking” of 9 km of this water main to increase its capacity from 13.5 to 20
M m3/yr by early 2011, so that it can better serve Lephalale as well as Medupi in its early stages of
operation.
Under country systems, DoEA requires a “Basic Assessment Report” for the
debottlenecking, and that report was publicly disclosed in draft for review and comment on November
2, 2009.
276.
Phase 1 of MCWAP involves construction of a new pipeline in the right of way of the present
one. The new main is expected to be operational by mid-2013, and the combined delivery capacity of
the two mains will then be 53.4 M m3/yr, of which Medupi will be using 3 M m3/yr by 2014. DWA is
proceeding in parallel with Phase 2 of MCWAP – the transfer of 169.3 M m3/yr through a new
pipeline from the Crocodile River to the Steenbokpan-Lephalale Corridor – and expects this transfer
infrastructure to be fully operational by the end of 2015. Phase 2 is effectively a large-scale water
reuse scheme, because the Crocodile River receives a large amount of treated wastewater from plants
in the northern parts of Johannesburg and Pretoria that are in the Crocodile River Watershed but are
supplied with water from the Vaal River Basin. The present volume of these return flows is 340 M
m3/yr, which is an amount roughly equivalent to the yearly natural runoff and groundwater discharge
from the Crocodile watershed.
277.
MCWAP has been planned for implementation by DWA with or without the Medupi Power
Plant, and Medupi will use only 6 percent of the volume of water it will provide to the LephalaleSteenbokpan region by the time Phase 2 is completed. DoEA requires EIAs for Phases 1 and 2, and
they are being prepared in parallel. DWA disclosed the Scoping Reports for both EIAs on November
2, 2009, and a revised Scoping Report for Phase 2 covering additional alternatives suggested by
stakeholders who took part in the initial scoping was disclosed on January 15, 2010. Once DoEA has
approved the scoping reports, the EIA phase will begin, likely in mid-2010.
278.
Complementary to the EIA process for Medupi, DoEA has initiated the preparation of an
Environmental Management Framework (EMF) for the surrounding Waterberg District Municipality,
where Medupi is located, as provided for as part of the NEMA EIA regulations issued in April 2006.
The objectives of the EMF are to ensure that water resources, biodiversity and associated ecosystem
services in the region are sustained and secured for the benefit of current and future generations.
March 2011 is the target date for completion. DoEA has successfully undertaken EMFs and is
73
implementing management plans for three other development-intensive regions in South Africa. The
GoSA is fully committed to completing the EMF in a timely manner. To this extent, an appropriate
covenant has been agreed with the GoSA under the Guarantee Agreement for the IBRD loan (see
Section III.F for the proposed covenant).
279.
In addition, because several coal-fired power stations are operating or being built on both sides
of the Botswana-South Africa border, and both countries envision future expansion of industry and
power generation in this area, there is a need to address the possible cumulative, long-range, and
transboundary effects of these investments. Consequently, in the course of preparation of the
Morupule B Generation and Transmission Project in Botswana, the Bank initiated discussions with the
authorities in both countries to jointly undertake a Regional Environmental and Social Assessment
(RESA). The terms of reference for the first phase of the RESA have been agreed with Botswana
Power Corporation, the Department of Environmental Affairs and the Department of Waste
Management and Pollution Control in Botswana, as well as with Eskom and the DoEA in South
Africa. The World Bank will use trust fund resources to carry out the first phase as well as the full
RESA, with full participation of the relevant authorities in Botswana and South Africa. The two
governments have already established a cooperative framework for the management of transborder
environmental and related social impacts from development projects affecting the two countries.
280.
The site selected for the Sere WPP is sparsely populated and, with the exception of one small
area at the northwestern corner that the EIA recommends be avoided, does not contain any unique or
rare vegetation. It is used for low-density sheep grazing. The single significant impact is the visual
presence of up to 100 wind turbines, mounted on 80-m pylons with blades 45 m in length. Between 40
and 50 of them will be installed in the first phase of the development, which EISP is supporting. The
visual impact cannot be mitigated, but the number of people affected will be small. Ultimately, the
WPP is likely to become a tourist attraction, for which the visual impact will be positive. Bird and bat
collisions that have been problems at wind generation sites are not expected to be major problems at
this one, according to the EIA, because the site is not on a known migratory corridor for either birds or
bats, and there are no significant terrestrial or marine bird rookeries or nesting areas in the project area.
281.
The Upington CSP site is on a single farm in an area that is also sparsely populated. The EIA
notes that the visual impact of the 210-m tower cannot be mitigated and recommends, instead, the
installation of a visitors’ center to serve tourists who are likely to be attracted to this unusual facility.
The other main impact described in the EIA is bird mortality, caused by collisions with the reflecting
surfaces of the heliostat and burning when birds pass through intermediate points at which the energy
from groups of heliostats is focused during the startup of each day’s operation. Noting that there is
very little experience with bird mortality at solar energy plants, the EIA expects the impact to be
moderate and recommends monitoring to measure the actual results.
282.
The most significant environmental impacts of the Majuba Rail Project will be strongly
positive: the replacement of 700 daily truck trips with six loaded and six empty trains pulled by
electric locomotives will: (a) eliminate the traffic that keeps roads in a continuous state of disrepair
and causes frequent and often fatal accidents, and (b) reduce annual CO2 emissions by an estimated
250,000 tons.
283.
Natural Habitats: The Medupi project is located in relatively flat terrain in the Bushveld, a
landscape dominated by thick growth of woody shrubs and low trees. The project area is occupied by
large game farms and scattered hunting lodges. Mammalian wildlife populations are managed by the
game farms. The project is located on land occupied by two game farms that were purchased by
Eskom and does not produce a significant loss of natural habitat. The transmission lines traverse
relatively small amounts of habitat that may support threatened flora or fauna. The most sensitive
habitat types identified are ridges and wetlands, and the mitigation measures recommended in the EIA
will reduce impacts on both of them to “low”.
74
284.
Neither the WPP nor the CSP are located in important natural habitat, and both sites have been
disturbed to varying extents by livestock grazing. However, field surveys did detect scattered
specimens of Red List plants and some birds and animals in vulnerable or near-threatened status
particularly at the CSP site. The EIAs recommend detailed surveys in advance of construction and
rescue programs to relocate plants or animals that cannot be avoided. The transmission line from the
WPP would have passed through one area of unique vegetation, but Eskom has accepted the EIA’s
recommendation to modify the alignment and avoid that area.
285.
The EIA for the Majuba Rail Project identified a number of sensitive natural features that
would potentially be damaged by construction of the track, including springs and wetlands, hillside
seeps, and a short but relatively broad section of the Vaal River floodplain that contains wetlands and
oxbow lakes. Eskom has adopted all the recommendations in the EIA for adjustment of the right-ofway alignment to avoid springs and seeps and to cross the Vaal River at a less sensitive location.
Stone-filled wetland “underpasses” will be installed as the railroad embankment is constructed in order
to maintain natural water flow in the wetlands.
286.
Physical Cultural Resources: The Physical Cultural Resources (PCR) safeguard is not
triggered by the Medupi Power Plant. During installation of the related transmission lines, graves may
be encountered, and the EIAs recommend detailed field surveys in advance of construction. Eskom has
developed the institutional capacity and effective procedures to implement South African legal
requirements, including standard procedures for “chance finds.” The procedures have been
successfully implemented at other sites where historic homesteads identified during the EIA process
have been preserved and protected, and human remains identified during both the EIA process and as
“chance finds” during site clearance have been exhumed and moved in accordance with national
standards.
287.
Sixteen Late Stone Age middens89 were found on the WPP site itself and, although small
adjustments in turbine footing locations can avoid some, it will not be possible to avoid all of them.
The middens are not considered to be particularly rich in artifacts, but they have research value that
will be lost once they are disturbed. The EIA recommends that Eskom apply for permits to sample
middens that cannot be avoided, under supervision of Heritage Western Cape. Once sampling is
complete and the materials have been properly stored, Eskom can apply for permits for destruction of
the remaining materials. The chance find procedures Eskom already has in place will be important
because there could be Early Stone Age material in deeper strata on the site.
288.
PCR is not an issue at the CSP site. In the case of the Ermelo-Majuba Rail Line, the EIA did
not identify any PCR. However, the detailed pre-construction survey of the right-of-way recommended
in the EIA revealed the existence of several graves. Those that were directly in the path of construction
have been relocated, in consultation with the affected communities and village leaders, and in a
culturally acceptable manner. The other graves are being protected by walls or fences to prevent
inadvertent damage during the installation of the rail line.
289.
Use of Country Safeguards Systems. In line with OP 4.00, an SDR has been prepared. A draft
of the SDR was publicly disclosed on November 11, 2009 and was the subject of a stakeholder
consultation workshop in Pretoria on December 9 and 10, 2009. The final SDR takes into account the
comments received at the workshop and in writing during the comment period, which ended on
January 10, 2010. The Executive Summary of the SDR is presented in Annex 11 of this PAD. In
89
A midden, also known as a kitchen midden, or a shell heap, is a dump for domestic waste. The word is of Scandinavian via
Middle English derivation, but is used by archaeologists worldwide to describe any kind of feature containing waste products
relating to day-to-day human life. They may be convenient, single-use pits created by nomadic groups or long-term,
designated dumps used by sedentary communities that accumulate over several generations. The late Stone Age is commonly
considered to have begun 50,000 years before the present and to have ended in Africa approximately 3,500 years before the
present.
75
keeping with best practice, all EIAs and EMPs for the project, which have already been disclosed to
meet DoEA and Eskom requirements in-country, have also been disclosed via the Infoshop. The gapfilling measures described in Annex 11 have been completed as described in Table 16 below.
Table 16: Use of Country Systems – Gap Filling Measures
Identified Gap
Gap-filling Measure
GoSA EIA Regulations do not require costs or
capacity-building to be included in alternatives
analysis for all types of projects.
Eskom standard procedures already call for consideration
of costs in alternatives analysis.
GoSA regulations on physical cultural resources do
not specify a chance finds procedure.
DoEA Records of Decision require chance finds
procedure. Eskom already has a chance finds protocol
that it incorporates in construction contracts.
GoSA regulations on land acquisition do not require
preparation and disclosure of stand-alone
resettlement action plans or public disclosure of
evaluations of resettlement and livelihood restoration
outcomes.
Eskom’s formal corporate resettlement procedure issued
in July 2009 specifies that resettlement action plans are
to be prepared and disclosed and that post-resettlement
independent audits will be conducted and disclosed.
290.
International Waterways. OP 7.50, Projects on International Waterways, is triggered by the
project because the water supply for the Medupi Power Plant and the subsequent additional allocation
for FGD will be sourced from phases I and II of DWA’s MCWAP and the Mokolo and Crocodile
rivers, which are tributaries to the Limpopo river. The Limpopo river forms the boundary between
South Africa and Zimbabwe and part of the Botswana-South Africa boundary, and it flows through
Mozambique to the Indian Ocean. OP 7.50 is not one of the safeguards policies covered under use of
country systems, hence the GoSA must meet the requirements specified in the OP. The GoSA
subscribes to the SADC Revised Protocol on Shared Watercourses, which describes how the countries
deal with and manage their use of the shared watercourses, including notification and provision of
information when required under the Protocol. Also, the four riparians have established the Limpopo
Basin Permanent Technical Committee (LBPTC) as a forum to inform one another and to discuss
plans involving shared water resources. In accordance with the Revised Protocol, the GoSA has
informed the riparians via the LBPTC of its planned MCWAP, under which it will supply Medupi and
other users in the vicinity of Lephalale and Steenbokpan with water from the Mokolo River and offset
the amounts consumed by transfers from the Crocodile River.
291.
The Acting Director of the GoSA Department of Water Affairs (DWA) reported to Eskom in a
letter dated December 18, 2009, that the MCWAP proposal was first discussed at the regular meeting
of LBPTC on July 6, 2007. LBPTC members were given updates at meetings on June 20, 2008, and
July 12 and November 19, 2009, all consistent with the provisions of the Revised Protocol. In
furtherance of the provisions of the Revised Protocol, the GoSA has provided additional information to
the other riparian states, in letters dated February 23, 2010, with which it transmitted copies of the
Scoping Reports for the two phases of MCWAP. Eskom has provided copies of these letters to the
Bank, through a letter dated February 23, 2010. The DWA, in its February 23 letter to the other
riparians, explained that there will be no adverse effects on any of the co-basin states because some of
the water will come from present allocations at the existing Mokolo Dam and the rest from surplus
return flows to the Crocodile River that do not originate in the Limpopo Basin.
76
F.
Safeguard policies
Safeguard Policies Triggered by the Project
Environmental Assessment (OP/BP 4.01)
Natural Habitats (OP/BP 4.04)
Pest Management (OP 4.09)
Physical Cultural Resources (OP/BP 4.11)
Involuntary Resettlement (OP/BP 4.12)
Indigenous Peoples (OP/BP 4.10)
Forests (OP/BP 4.36)
Safety of Dams (OP/BP 4.37)
Yes
[]
[]
[]
[]
[]
[]
[]
[]
No
[]
[]
[X]
[]
[]
[X]
[X]
[X]
OP/BP 4.00
[X]
[X]
[]
[X]
[X]
[]
[]
[]
not eligible for
piloting under 4.00
not eligible for
Projects on International Waterways (OP/BP 7.50)
[X]
[]
piloting under 4.00
In accordance with the SDR, Environmental Assessment, Natural Habitats, Physical Cultural Resources, and Involuntary Resettlement will
be handled under country systems, as provided for in OP 4.00 Piloting the Use of Borrower Systems to Address Environmental and Social
Safeguards Issues in Bank-Supported Projects. OP 7.50 Projects on International Waterways is not covered in OP 4.00 and therefore applies
to the proposed Project.
* By supporting the proposed project, the Bank does not intend to prejudice the final determination of the parties' claims on the disputed
areas.
Projects in Disputed Areas (OP/BP 7.60)*
G.
[]
[X]
Policy Exceptions and Readiness
292.
Past Procurement under Component A of the Project. South Africa faces near- and mediumterm electricity shortages. Taking into consideration the long lead time for such large investment,
Eskom began the procurement process for the Medupi Power Plant (Component A of the Project) in
2005 to avert the looming power crisis. At that time Eskom and the Government expected Eskom to
fund the program through a combination of internal cash generation and commercial debt. They had no
intention of seeking financing from multilateral institutions, such as the World Bank and, therefore,
had no reason to follow any procurement policies and procedures other than their own, i.e., the
procurement policies and procedures of Eskom. The situation changed when a combination of energy
and global financial crises resulted in major funding shortfalls.
293.
Construction of the Medupi Power Plant to satisfy the immediate energy needs requires the
continued performance of supply-and-installation and construction contracts that already have been
procured (which account for 58 percent90 of financing allocated to all contracts under this Project)
using the procurement policies and procedures of GoSA and Eskom. Going forward, Eskom has
committed to use the Bank’s Procurement and Consultant Guidelines to procure contracts for
procurement related to the Medupi Power Plant, associated transmission lines, and renewable and
energy efficiency investments (which account for 42 percent of financing allocated to all contracts
under this Project)91.
294.
Internal and external due diligence of the procurement processes of the Medupi Power Plant at
the project level and at the contract level have concluded that the procurement has been carried out in a
fair and transparent manner, and in compliance with the existing laws of South Africa. The process
followed focused on economy and efficiency, and gave opportunity to potential suppliers from both
developed and developing countries to participate in the bids. In addition, the Borrower has committed
to follow the Bank’s Procurement and Consultant Guidelines for future contracts, and agreed to the
inclusion (by contract amendment) of the Bank’s fraud & corruption and right to audit provisions in
the contracts already awarded by Eskom to be financed from the proposed loan.
90
91
Based on current cost estimates.
Based on current cost estimates.
77
295.
Construction of the Medupi Power Plant (Component A of the project) to meet South Africa’s
immediate energy needs requires the uninterrupted execution of supply-and-installation and
construction contracts that already have been procured using the Guarantor’s and the Borrower’s
procurement policies and procedures. This justifies an exception from the following specific
provisions of the policies relating to Bank Financing (OP/BP 6.00) and Procurement (OP/BP 11.00) in
order to allow Bank financing of contracts already awarded by Eskom using Eskom/GoSA procedures.
Therefore, a one-time exception from application of the Bank’s Procurement Guidelines is being
sought with respect to the contracts already awarded or in advanced stage of procurement and to be
financed under Component A of the Project. The Bank’s fraud & corruption and right to audit
provisions shall be incorporated into all such Medupi related contracts.
296.
A retroactive financing arrangement of up to 10.67% of the loan amount (up to US$400.00
million) will be provided to cover payments made prior to the signing of the Loan Agreement but on
or after January 1, 2007, for all eligible expenditures financed by the Bank loan. OP 6.00 (Bank
Financing), footnote 3, allows, in extraordinary circumstances, exceptions to the applicable conditions
for retroactive financing. One such condition requires that payments made by the Borrower should not
be more than 12 months before the date of Loan Agreement signing. Regional Management,
exercising the authority provided in such footnote, has agreed to the retroactive financing beyond the
usual 12 month period.
297.
Prospective Procurement. The ASGI-SA is an initiative of the GoSA, initiated in 2004, to
reduce poverty and inequity by steady improvement in the economy's performance and job-creating
capacity. The Constitution of South Africa has affirmative action provisions in the procurement
undertaken by the State or its institutions for advancement of previously disadvantaged persons or
categories of persons. One of the objectives is to advance Black Economic Empowerment. It is in this
context that public agencies including Eskom are required to seek local content and skills development
targets as key evaluation criteria in tenders that they award. Such practice does not align with the
Bank’s procurement policy as it does not fall under the Bank’s Domestic Preference provisions. The
Bank has reviewed a set of bidding documents for prospective procurement and found them equivalent
to the Bank’s SBDs with changes as permitted by the Guidelines (Paragraph 2.12). However, change
in contract terms post-award that provides an incentive through availability of more favorable contract
payment terms, which is not taken into account in the evaluation, but which potentially could affect
equal opportunity of some bidders (local or foreign) is not contemplated in the Bank Guidelines. It is
the Bank’s assessment that the risk of occurrence of such a scenario is low.
298.
Based on the above and country specific considerations noted, Board approval is being sought
for the inclusion of the ASGI-SA related provisions as proposed by the Borrower.
299.
The Project is ready for implementation. Component A (the Medupi Power Plant) is under
implementation by Eskom and the procurement plan for the first 18 months has been completed for
Components B and C.
78
Annex 1: Country and Sector or Program Background
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Country Background
1.
South Africa has a population of about 49 million and a GDP of about R2400 billion (about
US$300 billion). It is the largest economy in Africa, accounting for about 35 percent of the region’s
GDP and about two-thirds of the combined GDP of the Southern African countries. The largest
contributors to GDP are finance, real estate and business services (17.5 percent in 2008) and
manufacturing (16.9 percent).
2.
Supported by a strong infrastructure base, the country has done well in stabilizing and
strengthening its economy since transitioning from Apartheid in 1994. However, in recent years
bottlenecks have begun to appear. For example, the stable and low-cost electricity supply the country
has had over this period is now constrained, to the point that the demands of 2007/08 could not be met.
This had a severe impact on the economy, especially for the manufacturing and mining sectors, whose
operations had to be scaled down and some employees laid off.
3.
In the Budget Policy Statements of February 2009 and February 2010, the Minister of Finance
recognized that in the current economic context, South Africa would need to invest more in its
physical infrastructure in order for it not to become a binding constraint on growth. The Government
has decided to step-up infrastructure investments and support state-owned enterprises by providing
selective guarantees on their borrowings. In addition, appropriate pricing of utility services, such as
electricity needs to be encouraged for efficiency and for mobilizing long-term financing of capacity
expansion programs. The Government is also creating a more amenable environment for the private
sector to invest in economic and social infrastructure and to improve the operational and financial
efficiency of public sector institutions. Figure 1 below shows capital spending on infrastructure has
been trending upward in recent years.
Figure 1: Capital Spending on Infrastructure Sectors (as a % of GDP)
4.
Other key economic vulnerabilities and critical policy challenges have arisen in recent times.
Domestic investment remains constrained by relatively low levels of savings, and foreign investment
is relatively insignificant, particularly in “green field investments.” In addition to the weakening
infrastructure, investors appear to be deterred by certain factors, including crime, high cost of skilled
labor, exchange rate volatility, and labor relations.1 Strong domestic demand has led to rapidly rising
household indebtedness and imports, leading to widening of the current account deficit, as exports
1
Investment
Climate
Assessment,
2004;
Draft
Investment
http://rru.worldbank.org/Documents/EnterpriseSurveys/ICA/SouthAfrica.pdf
79
Climate
assessment,
2009
failed to keep up pace.2 High instance of HIV/AIDS has put tremendous strain on communities and
undermined the human capital base of the economy.
5.
Finally, although growth has been respectable, its distribution has not. A recent report from the
Presidency acknowledges increasing inequalities across race, gender and location. Between 1995 and
2005, inequality between racial groups increased from a ratio of 0.64 to 0.69. Such a rise in inequality
has at its base a growth pattern that did not create the jobs needed to give all South Africans a share in
the country’s success. Unemployment at 24.3 percent remains very high, and the legacies of Apartheid
continue to deprive the poor of access to economic opportunities and basic services.
Macroeconomic Update
6.
The South African economy seemed well-poised up until late 2007, before being buffeted first
by a power crisis and then by the global economic crisis. GDP growth exceeded 5 percent for a third
year running in 2007, bolstered by strong domestic demand, robust construction activity, and a marked
pick-up in services and manufacturing. Buoyed by a more favorable business environment and benign
global conditions, the private investment rate rose to 15.1 percent in 2007; up from 10.9 percent in
2002. The budget balance was in surplus for the second straight year in 2007, allowing national
government debt to GDP ratio to decrease by almost 5 percentage points to 28 percent. External debt
was at a reasonable 27 percent of GDP (40 percent of it Rand-denominated) by end-2007, and the
banking sector showed solid balance sheet positions with limited exposure to foreign currency debt
and interest rate fluctuation.
7.
Widespread power shortages in late 2007/early 2008, together with a slowing global economy
and lagged effects of earlier monetary tightening in an environment of high household indebtedness,
had, however, undercut the country’s growth prospects by the end of 2007. The FY09 budget,
presented in February 2008, had reduced the growth projections, from 5 percent in 2007 to 4 percent in
2008 and 2009. A reduction of close to one-half percentage point in growth could be attributed to
electricity shortages according to a 2009 Deloitte study on South Africa’s electricity sector.
8.
The global economic crisis, in particular, has taken a heavy toll on the South African
economy, which is only now beginning to emerge from its first recession in 17 years. News of GDP
growth of 0.9 percent (quarter-on quarter, seasonally adjusted and annualized) in 2009Q3 came as a
welcome respite following three consecutive quarterly declines during 2008Q4-2009Q2. Growth for
2009 is estimated at -1.8 percent, compared to last year’s projections of 3-4 percent for 2009.3 The
decline in economic activity, albeit widespread, has been particularly sharp in manufacturing and
mining,4 as the demand for the country’s exports plummeted, commodity prices fell sharply,5 and
domestic private sector demand came to a virtual standstill. Construction, buoyed by a massive
government spending program on roads, power, and stadiums for the 2010 soccer World Cup, has
been one of the only sectors to grow. Reflecting the economic slowdown, 870,000 jobs were lost
between 2008Q4 and 2009Q4, with the unemployment rate increasing from 21.9 percent to 24.3
percent.
9.
Fortunately, South Africa entered the downturn with a sound macro/fiscal position, enabling
aggressive countercyclical fiscal and monetary responses.6 In particular, fiscal space generated by
2
Import volume grew at an average rate of 12.4 percent over 2003-07, compared to only 5 percent growth for export
volumes.
3
GDP growth for 2009 was projected at 4 percent in the FY09 budget announced in February 2008, which the 2008 MTBPS
then revised down to 3 percent in October 2008.
4
Manufacturing output fell by 14.5 percent January-October 2009 relative to the same period in 2008, while mining was
down 7.3 percent over this time period.
5
Despite strong recovery in the past few months, most commodity prices remain below their pre-crisis levels.
6
The framework for South Africa’s response to the crisis was discussed and agreed upon by Government, labor, and
community representatives in February 2009. Key elements of the agreed framework included fiscal and monetary expansion,
80
several years of budgetary discipline and low public debt (net debt of the national government was just
22.7 percent of GDP by end-2008/09), together with South Africa’s deep and liquid capital markets
and continued access to global finance, allowed the government to undertake a substantial fiscal
expansion to offset the weak private sector demand. The emphasis has been on significantly scaling up
infrastructure spending and protecting and enhancing social sector spending in certain areas, despite a
major decline in revenues. Together with sizeable across-the-board salary increases in the public sector
in 2008/09 and 2009/10, this caused the fiscal balances to worsen from a surplus of 1.7 percent of
GDP in 2007/08 to a deficit of 7.3 percent of GDP in 2009/10: the ratio of public sector borrowing
requirement to GDP meanwhile increased from 0.3 percent to 11.8 percent. The 2010/11 Budget
purports to extend the expenditure trends, by proposing a R846 billion infrastructure investment plan
for the FY11-13 period, R454 billion of which would be incurred by large SOEs (including R309
billion by Eskom and R49 billion by Transnet) with substantial cover in the form of government
guarantees.7 Fiscal balances are projected to improve gradually over the medium term, an outcome
predicated upon revenues picking up with economic recovery and moderation of expenditure growth.8
The budget deficit and public sector borrowing requirement would fall to 6.2 percent and 11.1 percent,
respectively, in 2010/11 and further to 4.1 percent and 7.1 percent, respectively, by 2012/13.
Table 1: Key Economic Indicators
2007
2008
2009
2010
(Estimates)
2011
2012
(Projections)
Output and Prices
Real GDP Growth
5.5
3.7
-1.8
2.3
3.2
3.6
Headline CPI (annual average) inflation
6.1
9.9
7.1
5.8
6.1
5.9
5.9
9.0
-7.2
33.0
2.4
1.4
-7.1
34.1
-20.2
-18.3
-4.3
35.8
3.8
6.8
-4.9
35.8
3.9
4.9
-5.3
35.8
5.4
5.6
-5.8
..
3.7
4.6
4.5
4.2
3.9
..
30.2
28.5
1.7
23.2
-0.3
29.7
30.8
-1.0
22.7
4.0
26.8
34.1
-7.3
28.2
11.8
27.3
33.6
-6.2
33.2
11.1
27.9
32.9
-5.0
37.3
8.8
28.0
32.1
-4.1
39.8
7.1
Gross Domestic Investment
21.9
22.8
23.3
23.4
23.6
..
- Of which public fixed investment
6.2
7.5
8.4
8.7
8.9
..
- Of which private fixed investment
15.0
15.8
15.4
15.4
15.4
..
Gross national saving
14.6
15.4
16.4
16.4
16.4
..
21.3
9.6
9.1
10.6
11.6
External Outlook
Export Growth
Import Growth
Current account balance (% of GDP)
Gross official reserves (billion $)
- In months of next year’s Good and nonfactor Services imports
1/
Consolidated Govt. Finance ( percent of GDP)
Total Revenue
Total Expenditures and net lending
Overall budget deficit (excl. grants)
National Government Debt
Borrowing Requirement of Non-Financial Public Sector
Investment and Saving (% of GDP)
Money and Credit
Net Domestic assets
accelerated public sector investment, protection of jobs and investment in people and productive capacity, and supporting
vulnerable sectors such as clothing and textiles and automobile manufacturing.
7
Other areas of emphasis in the budget include employment programs, social security benefits, health, education, fighting
crime, and rural development.
8
Public expenditure is projected to grow at around 2 percent per year over the FY11-13 period, compared with 7.2 percent
growth during FY06-09.
81
2007
2008
2009
2010
Broad money (incl. forex deposits)
23.6
14.8
7.9
12.6
12.5
Repo Rate
11.0
11.5
7.5
..
..
(Estimates)
2011
2012
(Projections)
Source: National Treasury, South Africa, and IMF; 1/ The fiscal data under the column for year X are for fiscal year X/X+1.
10.
Longer-term fiscal sustainability remains of concern to the government as it carries out the
short-term stimulus. This is especially important in South Africa’s case given its reliance on domestic
capital markets for financing, for which it is critical that it retains its investment-grade sovereign
rating. Thus far, the markets have remained comfortable with the fiscal frameworks, despite the rising
government debt levels, and sovereign ratings have been maintained. Clearly, the solid record of fiscal
prudence and macroeconomic stability, transparent budgetary institutions, and broad political
consensus on sound public finances has worked in the government’s favor.
Figure 2: Trends in Budget, Public Sector Borrowing Requirement, and Public Debt (% GDP)
Source: National Treasury and Staff calculations.
11.
Even so, the budget will remain under considerable strain over the medium term because of
the high projected fiscal deficits. As per the latest estimates presented in the 2010 budget, the
Government will need to borrow R669 billion (US$88 billion at current exchange rate) over the
2009/10-2012/13 period, which would take its debt stock to R1.3 trillion by 2012/13. Or, the
government net debt stock would rise from 28 percent of GDP in 2009/10 to 40 percent of GDP in
2012/13, peak at about 44 percent of GDP in 2015/16, before stabilizing and falling gradually. This is
fairly modest in comparison to Brazil (63 percent), India (77 percent) and Hungary (80 percent).9 The
debt servicing cost to the government according to these estimates would increase from R57.6 billion
in 2009/10 to R104 billion in 2012/13, which would be 3.2 percent of GDP, the same as in 2007/08
and lower than in the previous years and thus within manageable limits.
12.
As seen in Figure 3, the non-interest expenditure as a share of GDP peaks in FY10 and then
falls by 2 percentage points by 2012/13. In the meanwhile, the fiscal revenue to GDP ratio improves
by more than one percentage point between FY10-13. The net result is a 3.3 percentage point
improvement in the primary budget balance, from -4.9 percent of GDP to -1.6 percent of GDP. This
trajectory toward achievement of a primary surplus yields the mentioned declining trends in
government debt from FY16 onward.
9
International Institute of Finance, March 2010, “South Africa: On the path to Fiscal Sustainability.”
82
Figure 3: Primary Budget Balance; 2006/07 – 2012/13
Source: 2010 Budget Overview, National Treasury, South Africa
13.
The 2010 Budget clearly presented a fiscal pathway toward sustainability, which, as noted, has
been deemed credible by independent analysts (including the International Institute of Finance and the
Economist Intelligence Unit) and markets alike. The main challenge on the expenditure side is going
to be holding back pressures for continued strong growth in public sector wages and increased social
expenditure. The Finance Minister took a firm line on wages in his budget speech when he said that
“Now that a major revision to public service remuneration is behind us, it will be necessary to
moderate salary increases going forward.” The revenue element of the fiscal improvement depends on
the strength of the economic recovery. While the fiscal framework presented in the 2010 Budget is
based on conservative GDP growth estimates, the risk from lower growth outcomes cannot be
discounted. However, on this South Africa’s fortunes are closely tied to that of the World economy
and to its own ability to tackle the emerging electricity supply constraints, the focus of this operation.
To the extent that the global recovery firms up further, as trends in the Global Economic Prospects
2010 confirm, that takes significant pressure off the fiscal situation in South Africa. Moreover,
Eskom’s expenditure plan, which is substantial in size with commensurate pressures on public sector
finances in the medium-term, has high likely growth pay-off and would therefore improve prospects of
longer term fiscal sustainability by moderating the debt to GDP ratio and bringing forward the time
when the ratio begins declining. The National Treasury’s quantitative analysis of fiscal sustainability
is presented on pages 61 and 62 of the 2010 Budget Document. A key conclusion of its analysis is that
the probability of the debt stock breaching 50 percent of GDP threshold is low – the probability peaks
at 36 percent in 2017/18.
14.
Total net debt plus contingent liabilities and provisions are projected to increase from 33.8
percent of GDP on March 31, 2009 to 53.6 percent by 2012/13 and peak at about 60 percent of GDP
by 2015/16, the upper limit of the SADC’s macroeconomic convergence target. Contingent liabilities
would reach around R376 billion by end-2012/13, R176 billion of it being the guarantee to Eskom
approved in February 2009. Other state guarantees include R15.2 billion for the Development Bank of
South Africa (DBSA), R2.5 billion for the Land Bank, R1.5 billion for South African Airways, R1.4
billion for Autopax Passenger Services, R1.3 billion for Denel (the defense equipment manufacturer),
and R1 billion for the South African Broadcasting Corporation. More details on the Government’s
contingent liability position are available on pages 94-96, and 98-100 of the 2010 Budget Document.
15.
Prompted by the economic slowdown and improving outlook for inflation, SARB slashed the
repurchase rate by 500 basis points between December 2008 and August 2009. At 7.0 percent, the repo
rate is at its lowest since June 2006. CPI inflation, at 6.2 percent in January, slipped within SARB’s 36 percent target range for the first time in 30 months in October 2009, benefiting from a strong Rand
and subdued spending by the private sector. Nonetheless, SARB’s Monetary Policy Committee
decided against any further cut in the interest rates since August, citing looming electricity tariff
83
increases and double-digit wage increases earlier in the year as the downside risks. Fueled by global
petroleum and food prices, and adjustments in domestic administered electricity prices, CPI inflation
had reached 13.6 percent in August 2008, uncomfortably above the SARB’s 3-6 percent target range.
The trend has since been reversed, as global energy and food prices fell sharply from their historical
peaks and monetary tightening took effect. Producer price inflation has fallen even more sharply, from
a peak of 19.1 percent in August 2008 to 2.7 percent in January 2010.
16.
The strong macroeconomic response by the authorities, combined with the improved global
economic environment, helped end the recession in 2009Q3. The manufacturing sector, recovering
from an 11.1 percent decline in Q2, led the return to positive growth in 2009Q3, with 7.6 percent
growth (quarter-on-quarter, seasonally adjusted and annualized) in 2009Q3,10 followed by
construction, government services, and utilities (electricity, gas and water).11 Construction activity
grew at an annualized rate of 6.1 percent in Q3, reflecting continued strength of public sector
investment in the sector, as private sector engagement in real estate and building activity remained
subdued. Positive growth in general government services (4.9 percent), personal services (3.5 percent),
and transport and communication (1.2 percent) offset declines in wholesale and retail trade (1.1
percent) and finance and business services (1.5 percent), enabling the services sector as a whole to
grow at 0.8 percent (quarter-on-quarter, seasonally adjusted and annualized) in 2009Q3. Benefiting
from renewed demand for commodities in China, export volumes grew by 3 percent in 2009Q3.
Table 2: Quarterly GDP Growth (percentage change in seasonally adjusted annualized rates)
Total GDP
Primary Sector
Agriculture
Mining
Secondary Sector
Manufacturing
Construction
Tertiary Sector
Government Services
Q1
2.5
-8.7
12.8
-15.8
0.2
-0.1
3.7
4.8
4.4
Q2
5.5.
9.3
6.2
10.5
14.0
17.4
5.4
2.6
2.5
2008
Q3
1.3
-2.3
17.8
-9.5
-2.5
-5.2
8.6
3.8
6.2
Q4
-0.7
1.7
5.6
0.1
-12.9
-17.4
6.3
4.2
6.2
Q1
-7.4
-23.4
-3.7
-30.7
-19.4
-25.5
10.7
-0.9
2.1
2009
Q2
-2.8
6.0
-13.1
15.8
-6.9
-11.1
8.7
-1.7
3.1
Q3
0.9
-7.0
-9.8
-5.8
7.0
7.6
6.1
0.8
4.9
Final Consumption Expenditure
Households
General Government
Gross Fixed Capital Formation
Private
Public Corporations
General Government
Gross Domestic Expenditure
2.9
2.9
11.6
17.5
9.7
58.1
16.3
14.7
0.6
0.6
-2.3
7.9
5.6
17.3
7.9
-2.5
-1.5
-1.5
10.1
12.4
5.3
46.1
10.0
0.7
-2.2
-2.2
3.5
2.8
4.0
-2.1
3.4
-2.7
-5.8
-5.8
6.4
7.4
-16.8
152.3
1.6
4.7
-6.1
-6.1
0.8
-0.9
-9.4
23.4
2.0
-12.1
-2.0
-2.0
7.5
-4.1
-14.1
18.7
4.4
-1.7
Source: South African Reserve Bank
17.
Growth is projected in the 2010 Budget to improve gradually, from 1.8 percent in 2009, to
2.3 percent in 2010 and further to 3.6 percent by 2012. Recovery in global demand for South African
exports and a pick-up in global commodity prices, based largely on continued strong demand in China
and India, will be important for improved growth performance of the South African mining and
manufacturing sectors. Sustained large infusions of public sector investments are essential to
10
Recovery in manufacturing reflected strong performances by motor vehicles, electrical machinery, and food and beverages.
Encouragingly, the manufacturing activity carried its positive Q3 momentum into November, when the PMI (seasonally
adjusted) rose above the critical 50 index point level for the first time since April 2008. Roughly, a PMI reading of over 50
reflects expansion in the sector.
11
Reflecting stronger manufacturing activity, electricity consumption rose 1.4 percent m/m (seasonally adjusted) in October
2009 and by 2.1 percent in the three months ended October compared with the previous three months.
84
addressing the significant gaps in infrastructure, especially electricity generation and transport.
Together with complementary policy measures to free up product market competition, these
investments would lay the basis for enhanced participation by private investors – in large scale
infrastructure as well as smaller private enterprise. The Government would like to see a more
competitive exchange rate, although the policy mix to achieve that is not clear at the moment.
Continued focus on low and stable inflation and rollback of the countercyclical fiscal measures, as
indicated by the 2010 Budget, would maintain macroeconomic stability and sustainability in the
country, which for some time have been among the key attributes of the South African economy that
have sustained the interest of foreign investors. The growth dividend of the FIFA World Cup could be
as high as 0.5 (2010 Budget) to 1.0 (EIU estimate) percentage point in 2010, benefiting from tourism
and related services for the additional 500,000 tourists that are expected during the event. In the
meanwhile, structural issues such as lack of skills, impairment of human development by HIV/AIDS,
low savings rates, and geographical segregation of informal settlements will continue to act as
restraints on growth.
18.
Economic recovery remains tentative and uneven, however, particularly on account of
continued weakness in domestic private sector demand.12 Large-scale job loss (870,000 in 2009) led to
a 1.1 percent decline in disposable incomes in 2009Q3 of households.13 Private credit fell for the first
time in over 40 years in October and again in November.14 It is especially worrying that private sector
confidence in the economic recovery is still to develop, causing it to shy away from fixed investment.15
In addition, mining exports have weakened, despite record gold prices and strong recovery in
platinum, due to structural issues at mines and a strong Rand. At the same time, prospects remain
uncertain in the agriculture sector, where lower domestic incomes, declining producer prices and rising
costs of intermediate inputs (including fertilizers) resulted in negative growth in each of the first three
quarters of 2009. Manufacturing output, despite the turnaround in 2009Q3, was still down 11.2 percent
year-on-year in September 2009, with each sub-sector, except food and beverages, recording lower
output relative to September 2008.
19.
South Africa’s external and financial sectors remain robust despite the global crisis. After an
initial dip, foreign portfolio investment has recovered strongly, comfortably covering South Africa’s
large current account deficit (7.1 percent of GDP in 2008 and an estimated 4.3 percent of GDP in
2009). Foreigners net purchased over US$10 billion worth of equity on the Johannesburg Stock
Exchange in 2009, exceeding the net outflow of about US$6.3 billion in 2008. In addition, a slump in
imports and a mild recovery in exports have ended a prolonged period of trade deficit, taking
considerable pressure off the current account. These developments on the BOP have led to a full
recovery in the value of the Rand against the major currencies: the Rand/US$ rate and the nominal
effective exchange rate stand firmer today than at end August 2008, just before the onset of the global
16
crisis. Leaning against the wind to prevent excessive appreciation, SARB accumulated international
reserves, taking gross reserves from $34.1 billion at end-2008 to $39.5 billion at end-January 2010.
20.
South African banks remain in a sound position to weather the global financial storm,
benefiting from limited exposure to foreign currency debt and more disciplined lending practices
ensured by the National Credit Act of 2007. According to a recent SARB Supervision Report, local
banks’ capital-adequacy ratio increased from 11.8 percent to 13 percent over 2008 and liquid assets
12
Household spending fell for the 5th consecutive quarter in 2009Q3, reaching 61 percent of GDP, the lowest since 1994Q1,
as households, overburdened with debt, continue to deleverage despite lower interest rates.
13
The ratio of household debt to disposable income stood at 79 percent in 2009Q3, down from 80.1 percent in the previous
quarter.
14
Private sector credit demand fell 1.6 percent y/y in November 2009, the sharpest annual decline in 43 years.
15
Gross fixed capital formation by the private sector fell by 14.1 percent in 2009Q3, following declines of 16.8 percent and
9.4 percent, respectively, in Q1 and Q2 of 2009, as firms feverishly ran down inventories rather than invest in production
expansion to meet demand, in an apparent lack of confidence in the durability of the recovery.
16
Among the emerging markets, in 2009 the Rand’s recovery against the US$ was second only to the Brazilian Real’s.
85
held by banks exceeded statutory requirements throughout 2008. Implementation of the Basel II
process has been of high quality. The ratio of non-performing loans (NPLs) to loan advances increased
from 2.8 percent in July 2008 to 5.5 percent in August 2009 as a result of the crisis, but remains
manageable.
Sector Background
A. Energy Resources in South Africa
21.
South Africa has very little crude oil or natural gas, but it has the world’s sixth largest
recoverable coal reserves, estimated at 54 billion short tons (about 5 percent of the world’s reserves).
Proven oil reserves are estimated at 15 million barrels and natural gas at 318 billion cubic feet (Bcf).17
As Figure 4 shows, domestic production of oil amounts to approximately 40 percent of total
consumption, but a significant percentage of the oil produced is from coal (synthetic oil). Sasol, the
biggest local company listed on the South African stock market, produces synthetic fuels from lowgrade coal and a small amount from natural gas. It operates the world’s only coal-to-liquids synthetic
fuels facility, and produces around 36 percent of liquid fuels consumed in South Africa.
Figure 4: South Africa’s Oil Production and Consumption, 1980-2007
22.
As estimated in 2006, South Africa produced 102 Bcf of natural gas and consumed 109 Bcf;
the remaining 7 Bcf being in the form of imported Natural Gas Liquids (NGL). Most of South Africa's
natural gas production is synthetic gas from coal. Exploration for natural gas is continuing in Mossel
Bay.
23.
Accordingly, coal is the main energy resource available for power generation in South Africa.
Coal has traditionally dominated the energy supply sector in South Africa, from as early as 1880 when
coal from the Vereeniging area was supplied to the Kimberly diamond fields. The later gold
discoveries in the Witwatersrand area and the growing rail infrastructure placed increasing demands on
coal. As South Africa evolved into a mining giant, coal was used more and more to generate steam,
compressed air and then electricity.
24.
South Africa is the fifth largest coal producing country in the world, producing an average of
224 million tons of marketable coal annually. Twenty five percent of this production is exported
internationally, making South Africa the third largest coal exporting country. The remainder of South
Africa’s coal production feeds the various local industries: Fifty three percent is used for electricity
17
Energy Information Administration, Country Analysis Brief, October 2008.
86
generation, 33 percent for petrochemical industries (Sasol), 12 percent for metallurgical industries
(Iscor) and 2 percent for domestic heating and cooking. At current production rates the coal supply
should last another 200 years.
25.
Typically, South African exported coal has a heating value above 23 MJ/Kg. The coal-fired
power plants burn domestic coal with a heating value in the 14-20 MJ/Kg range (average: 17 MJ/Kg)
and 0.6 to 2.5 percent (average: 0.8-0.9 percent) sulfur content. In the past (see Figure 6), coal was
available to Eskom at very low prices (R40-80/ton), but increasing international demand for coal has
increased prices substantially (up to R300/ton for spot purchases). This is the case not only for the high
quality coal which is exported, but also for the lower quality coal which used to be purchased only by
Eskom.18
Figure 5: Coal Prices
26.
Environmental concerns pose the main challenge to coal as an energy source. Not only does
the burning of coal cause air pollution, mining activities to extract the coal also have a severe impact
on the environment. Advances in technology are now starting to guide international and local
industries in how they can control the use of fossil fuels, coal in particular.
Figure 6: South African Coal Price and Consumption
18
Eskom had to purchase approximately 20 percent of its coal in the spot market in 2008 considerably increasing its
operating costs.
87
27.
South Africa also has the potential to use coal to generate methane. Coal Bed Methane (CBM)
potential is estimated to be at least 3,500 PJ19 in South Africa but has not been developed yet.
Exploration has been initiated at a number of sites (e.g., Bothaville Magisterial District of the Free
State Province, and in the Waterberg region, close to the Medupi Power Plant). In the Waterberg
region the resource is expected to exceed 1 TCF, and a pilot project that includes a pioneering clean
energy fuel cell using the gas is underway. Another pilot involving coal gasification for power
generation is underway in the Majuba area, where it is not commercially viable to mine the coal. The
project is expected to culminate in about 2000 MW equivalent of gas-fired power plants.
28.
South Africa also uranium reserves estimated at 157,853 PJ20 thus allowing for further
development of its nuclear power program. South Africa currently operates one nuclear facility,
Koeberg, located near Cape Town. The plant, consisting of two 965 MW reactors (actual total net
capacity 1,840 MW), is the only nuclear power plant on the African continent.
29.
South Africa has an attractive range of renewable resources, particularly solar. Renewable
applications are the least cost energy service in many cases from a fuel resource perspective (i.e., the
cost of fuel in generating electricity from such technology); more so when social and environmental
costs are taken into account. However, the capital-costs are high. South Africa has been endowed with
considerable potential for solar energy (estimated at 8,500,000 PJ/yr), and limited wind (220 PJ/yr)
resources. Also, small hydro and biomass are available at 20 PJ/yr and 323 PJ/yr, respectively. As a
result, solar and wind are the two priority options for potential renewable energy development. Solar
development will follow the evolution of new technologies suitable for baseload operation.
30.
The government has announced its target to generate 10,000 GWh from renewable sources by
2013 and is currently finalizing proposals to ensure that this target is met (the proposed Component
C.2 is being developed by Eskom in support of this target). To help achieve this target, the regulator
has also announced feed-in tariffs for wind power, hydropower, landfill gas and CSP. If financial
support is available, about 900 MW of wind projects could be developed in the next 10 years, with a
longer-term target of 4,500 MW.
31.
While many regional energy resources are potentially available (hydro from DRC,
Mozambique and Zambia, coal-fired power from Botswana and gas-fired power from Namibia and
Mozambique), they will not be developed soon enough to address the short-term needs of South
Africa. Other than nuclear power, which has been shown to be prohibitively expensive, the country has
no other renewable or low carbon source that could substitute for coal for baseload operation. The only
other renewable source, hydro, is exhausted; its developed potential is only used for peaking.
B. Electricity Sector Institutions
32.
The principal entities in the South African electricity sector are:
a. the Department of Energy (DoE), which is the national government ministry
responsible for developing policy for the sector and formerly a part of the Department
of Minerals and Energy (DME);
b. the National Energy Regulator of South Africa (NERSA), which has regulatory
authority in the sector;
c. Eskom Holdings Ltd. (Eskom), the publicly-owned vertically integrated utility
company; and
d. the Municipal Electric Utilities (MEUs), which provide distribution services to about
60 percent of the power customers in South Africa, by number (40 percent of the total
19
20
Source: South Africa/Initial National Communication to UNFCCC, October 2000
Source: South Africa/Initial National Communication to UNFCCC, October 2000
88
amount of power consumed), with the remainder being supplied by the distribution
component of Eskom.
Figure 7: Electricity Sector Structure
GoSA
Regulations & Policies
DME
DPE
100% Shareholder
NERSA
PPAs*
Eskom Holdings Ltd.
REDs
(187 in Number)
IPPs
Rules and Decisions
96% of Total
Generation
100% of Total
Transmission
40% of Sales
60% of Sales
Distribution
* The Electricity Regulations permits PPAs with other Buyers
33.
The Department of Energy: The DoE is the entity that develops policy measures for the
electricity sector, which are expressed in primary or secondary legislation, or by way of policy
statements. Legislation, such as the 2008 National Energy Act, is subject to approval by Parliament,
and major policy statements, such as the 1998 Energy White paper or the 2008 Electricity Pricing
Policy, are considered by the Cabinet. Other policy initiatives, such as the proposed 2009 Electricity
Regulation, only require approval by the Minister of Minerals and Energy.21
34.
In accordance with Section 33 of the Constitution of the Republic of South Africa, and the
provisions of the 2000 Promotion of Administrative Justice Act, the DME undertakes public
consultation processes before issuing final versions of policy pronouncements or of secondary
legislation. DME also hosts South Africa’s Designated National Authority (DNA), which approves
projects for the Clean Development Mechanism (CDM).
35.
The National Energy Regulator of South Africa: NERSA was established as an independent
regulatory authority pursuant to the National Energy Regulator Act, 2004. Initially, NERSA had
responsibilities only for the regulation of piped gas and petroleum pipelines but, in 2006, it was given
regulatory responsibilities for the electricity sector (which had previously been under the jurisdiction
of the National Electricity Regulator), pursuant to the Electricity Regulation Act, 2006.
36.
For the electricity sector, NERSA is responsible for:
a. issuing licenses (with terms and conditions) to entities engaged in the generation,
transmission, distribution, import/export and trade of electricity;
b. maintaining a register of entities engaged in the above-noted activities that do not need
to be licensed under the Electricity Regulation Act, 2006; such as non-grid supplies of
electricity for residential use, and
c. monitoring compliance with license terms and conditions.
37.
As part of its licensing function, NERSA is also responsible for the economic regulation of the
sector, including:
a. evaluating tariff applications from licensees; and
21
The Ministry of Minerals and Energy has been recently reorganized and is being led by two separate Ministers, one for
Energy and one for Minerals.
89
b. issuing tariff guidelines and methodologies (such as the proposed Multi-Year Price
Determination methodology, known as MYPD).
38.
NERSA’s other responsibilities in the sector include the regulation of Eskom and the
numerous municipal and private distribution companies. The regulation of Eskom’s generation,
transmission and distribution services is relatively intense, as evidenced by NERSA’s February 24,
2010 Decision in respect of Eskom’s MYPD 2 tariff application. In contrast, a somewhat lighter form
of regulation is employed in respect of the licenses and tariffs of the municipal distribution companies.
(For example, NERSA approved, on December 20, 2007, a generic Municipal Tariff Guideline
Increase of 12 percent, and subsequently received, reviewed and approved 163 tariff applications from
municipal distributors).
39.
Eskom Holdings Limited: Eskom Holdings Ltd. (Eskom) is South Africa’s national, vertically
integrated electricity utility, and is wholly owned by the Government, through the Department of
Public Enterprises (DPE). Eskom’s current structure is defined by the Eskom Conversion Act of 2001
and its operations regulated22 by NERSA, and by the National Nuclear Regulator in terms of the
National Nuclear Regulatory Act (47) of 1999. The utility employs about 35,500 people (reduced from
about 66,000 over the past two decades). Eskom is responsible for most of South Africa’s electricity
generation, all transmission, and 40 percent of distribution (by percent of population).23
40.
Eskom operates its business through a number of divisions and subsidiary companies. The
following chart shows the current structure of the Eskom Group, including the major subsidiaries
(Figure 9). Eskom’s core business as a utility is carried out by the three divisions under the heading
Eskom Core Business and is described below, followed by a brief description of the operations of the
key subsidiaries.
41.
Eskom is the 13th largest power utility in the world in terms of generating capacity and the 9th
in terms of sales, which is a sign of comparatively better capacity utilization. Eskom’s generation
assets comprise 26 medium- and large-sized power stations under operation, with a cumulative net
capacity of about 38,000 MW. Thirteen of these are coal-fired and account for 87 percent of total
capacity (92 percent in terms of energy). Hydropower (8), including pump storage, accounts for 6
percent; nuclear (1), for 5 percent; and liquid-fueled gas turbines (4), for 2 percent. Eskom imports
1,700 MW from Mozambique and currently exports to neighboring countries of Swaziland, Lesotho,
Mozambique, Botswana, and Namibia.
Figure 8: Eskom Holdings Business Structure
Eskom Holdings Ltd
Eskom Core
Generation
-Generation
-Primary energy
-Enterprises
Customer Networks
-System ops and
planning
- Transmission
-Distribution
Subsidiaries
Corporate
- Finance
-Corporate services
-Human resources
22
Eskom Enterprises (Pty) Ltd
-Rotek Industries (Pty) Ltd
- Roshcon (Pty) Ltd
- Eskom Uganda Ltd
- arivia.com (Pty) Ltd
- Eskom Energie Manantali SA
Eskom is regulated under licenses granted by the National Energy Regulator of South Africa (NERSA), originally under
the Electricity Act (41 of 1987), and replaced by licenses under the Electricity Regulation Act (4 of 2006), and by the
National Nuclear Regulator in terms of the National Nuclear Regulatory Act (47 of 1999).
23
Private generators account for about 3 percent of generation (mostly for their own consumption) and municipalities account
for the remaining 1 percent. RED authorities (185 in total) manage the balance of electricity distribution by buying power in
bulk from Eskom. The DPE as the single shareholder on behalf of the Government oversees the operations of Eskom, which
is set up as a Public Company as per the terms of the 2001 Eskom Conversion Act.
90
Figure 9: Eskom Subsidiaries
Government of the
Republic of South Africa
(Shareholder Representative : Minister of Public Enterprises)
Eskom Holdings Limited
(Reg No. 2002/15527/06)
Subsidiaries
Escap Limited
Eskom Finance
Company (Pty) Ltd
Eskom Development
Foundation
(Section 21 Company)
Gallium Insurance
Company Limited
Eskom Enterprises
(Pty) Ltd
PN Energy Services
(Pty) Ltd
Eskom Pension &
Providend Fund
Figure 10: Eskom’s International Presence
Figure 11: Operational Efficiency of Developed Utilities
42.
Eskom’s past and projected operational performance from the financial perspective is provided
in Annex 4. Its past performance compares favorably with that of other similar utilities in large middle
income countries such as Brazil and Russia, as well as some OECD countries. In terms of operating91
cost, it is the lowest cost operator as depicted in Figure 11. For many years, Eskom has been among
the lowest cost electricity producers in the world. One of the reasons for this is South Africa’s
abundance of coal. For the past two decades it has not been necessary to invest in new power stations
as supply of electricity far exceeded demand and some of the plants were mothballed. The lack of need
to invest in large generating assets for a long time and a financially depreciated system enabled Eskom
to keep the price of electricity down.
43.
However, an electricity crisis has developed in South Africa over the past few years, first
manifesting as a peak capacity problem and developing into a deeper energy crisis in early 2008.
During the crisis, Eskom introduced a power conservation program to align consumption and demand
with the limited supply available. This was to some extent achieved in mid-2008 when some of the
mothballed capacity became operational.
44.
To meet the growing needs of the economy and to mitigate the risk that the current financial
crisis and possible supply shortages could further impact the success of access to electricity to date,
Eskom’s long-term strategy is to develop 20,000 MW of new generating capacity.24 To this extent,
Eskom plans to bring on line in the next seven years about 9,600 MW of new coal-based generating
capacity. In addition 1,300 MW of peak power is expected to be generated from a pumped hydro
scheme and about 200 MW from development of RE (CSP and Wind) projects.
45.
Municipal Electric Utilities: There are 187 MEUs providing distribution services in South
Africa. There is significant disparity in the size and degree of sophistication of these entities, which
range from relatively large, well-organized undertakings in the major urban centers, to extremely small
operations with very few employees in more remote locations. These 187 MEUs purchase electricity in
bulk from Eskom, which as noted above, also carries on its own distribution business in various parts
of the country. It is a highly fragmented structure for the distribution industry, which contributes to the
adverse financial state of the distribution sector. This is further aggravated by inefficiencies, disparities
in tariffs, unequal treatment of customers, inadequate maintenance of networks and an inability to
capitalize on economies of scale.
46.
Approximately 148 of the MEUs belong to a voluntary trade group known as the Association
of Municipal Electricity Undertakings (AMEU). NERSA exercises some degree of regulatory control
over the MEUs, but not all of the MEUs’ tariffs are set by the regulator. For a number of years,
attempts have been made to rationalize this aspect of the sector. Following a lengthy debate, the 1998
Energy White Paper endorsed the recommendation of the DME that the electrical distribution
industries should be consolidated into a number of financially viable and independent Regional
Electricity Distributors (REDs), and that cost-effective tariffs should be introduced. Subsequently, in
2003, the DME incorporated Electricity Distribution Industry Holdings (Pty) Ltd (EDI Holdings) for
the purpose of facilitating the restructuring of the electricity distribution industry in accordance with
the requirements of the 1998 Energy White Paper and subsequent Cabinet decisions. In 2006, the
Cabinet decided that:





an arrangement of six ‘wall to wall’ REDs would be implemented;
the REDs would be established as public entities and be regulated according to the 1999
Public Finance Management Act and the Electricity Regulation Act, 2006;
Eskom would become a shareholder in the respective REDs for a transitional period,
reducing its shareholding over time;
the DME, through EDI Holdings, would oversee and control the REDs;
a roadmap would be put in place to move from the current scenario into the future industry
structure;
24
This massive expansion plan is larger than the combined undeveloped generation potential of Mozambique and Zambia,
two countries that have the most feasible sources of regional supply in the medium term, and much larger than all generation
projects that have been deemed feasible in the sub-region.
92



a strategy would be developed to deal with capital investment requirements for the REDs;
EDI Restructuring legislation would be introduced; and
a National Electricity Pricing System would be developed.
47.
The Electricity Regulatory Act, 2007 explicitly gives NERSA the power to regulate
“reticulation,” and to prescribe key performance indicators for municipal reticulation systems.
Although consultations on this issue have continued, and some initiatives have been taken to move the
process forward (including the preparation of draft legislation and the incorporation of a “pilot” RED),
the ensuing restructuring of the distribution subsector remains unresolved. The draft legislation is
being processed for parliamentary approval (see Paragraph 83 for more details regarding proposed
sector restructuring).
C. Electricity Sector in South Africa: Generation, Distribution & Transmission
48.
Electricity generation: As of January 1, 2009, the total installed capacity of South Africa was
43,257 MW, with Eskom plants representing 42,109 MW and other plant owners having the remaining
1,148 MW.25 Eskom’s installed power generating capacity includes a nuclear plant (1,800 MW), coalfired power plants (33,036 MW), pumped storage (1,400 MW), open cycle gas turbines (2,414 MW)
and the remaining hydropower. The coal-fired plants, along with the Koeberg nuclear power plant,
constitute the baseload capacity of South Africa. The Koeberg plant has been in operation for
approximately 30 years. Also, electricity is being imported from the Cahora Bassa hydro plant
(installed capacity 2,075 MW) in Mozambique.
49.
With the exception of the Majuba power station26 (3,843 MW), all other coal-fired power
plants have been in operation for 20 to 40 years. Some of the thermal power stations had been
mothballed for years, and recently returned to operation. These plants represent approximately 3,800
MW, and bringing them back to service required a total investment of R20 billion:



Camden (8x200 MW) return to service in 2003-2008;
Grootvlei (6x200 MW) return to service in 2005-2009; and
Komati (4x125 MW + 5x100 MW) return to service in 2005-2010.
50.
Table 3 provides an overview of the generation capacity present in the South African
Electricity Sector.
Table 3: Existing Power System (as of 2009)
Type
Coal-fired
Camden
Grootvlei
Komati
Arnot
Hendrina
Duvha
Kriel
Kendal
Matla
Matimba
No of Units in
Service
Unit Size
(MW)
Total ( MW)
8
6
9
6
10
6
6
6
6
6
190
180
102
381
190
575
475
640
575
615
1520
1080
918
2286
1900
3450
2850
3840
3450
3690
25
This is installed capacity; available capacity is less than installed capacity and varies from year to year.
The first unit in Majuba went on load in April 1986; the fourth unit was commissioned in 1999. The fifth unit was
commissioned in 2000, and the sixth in 2001.
26
93
Type
Lethabo
Tutuka
Majuba Dry
Majuba Wet
Total Coal-fired
Nuclear
Koeberg
Total Nuclear
Hydro
Gariep
VD Kloof
Total Hydro Capacity
Pumped Storage Hydro
Drakensberg
Palmiet
Total Pumped Storage
Gas Turbines
Acacia
Port Rex
Ankerlig (Previously Atlantis)
Gourikwa (Previously Mossel Bay)
Total Gas Turbines
Total Eskom Generating Plants
Coal-fired
Kelvin A
Kelvin B
Rooival
Pretoria West
Sasol SSF
Total coal-fired
Others
Steenbras Pumped Hydro
Mini Hydro
Total others
Total non-Eskom System
No of Units in
Service
Unit Size
(MW)
Total ( MW)
6
6
3
3
593
585
612
669
3558
3510
1836
2007
35,895
2
900
1800
1,800
4
2
90
120
360
240
600
4
2
250
200
1000
400
1,400
3
3
9
5
57
57
148
148
171
171
1332
740
2,414
42,109
1
2
3
4
10
25
51.5
51.5
25
52
25
103
155
100
520
902.5
3
1
60
65
180
65
245
1148
Total System
43,257
51.
To maintain these assets, Eskom has a well developed and comprehensive O&M strategy
which also focuses on improvement in plant reliability and efficiency. As is customary with large coal
fleets, the boilers, steam turbines and electrical equipment have been identified as the components
causing most of the forced outages and a strategy has been developed on how to improve the reliability
of these systems. In addition, condition and performance monitoring systems are being implemented.
52.
Electricity Distribution: A program of progressive rationalization of the distribution business
with the objective of improving its overall efficiency has been formulated. In October 2006 the
Cabinet approved the proposal to create the six REDs to consolidate the electricity distribution
businesses of the municipalities and Eskom, as discussed in paragraph 46 above. EDI Holdings is
responsible for implementing the GoSA’s restructuring policy. The critical next steps include the
approval of enabling legislation, which is currently under consideration. Steps are also underway to
rationalize the transmission and system operation functions. The Government also undertook a
94
massive electrification program as part of the post-apartheid efforts, designed to improve the
distribution of incomes and quality of life for the poorer segments of the population. Electrification
rates have decelerated in the recent past, as financial issues have limited the sector’s implementation
capacity.
53.
Transmission System: The transmission system of South Africa consists of approximately
28,000 km of high voltage lines above 132kV (see Table 4) and is owned and operated by Eskom.
Table 4 shows the transmission projects for the period 2007 – 2018 (10-Year Transmission
Development Plans), while Figure 12 shows the committed projects (next 5 years, up to 2013). The
projected investment is R43,459 million.
Table 4: Transmission Assets, Present and Planned
Transmission Asset
Installed capacity @
Dec 2007
Additional New Assets
@ end 2018
14,291
Total kms of line
27,817
765kV Lines (km)
1153
5,770
400kV Lines (km)
16191
7,867
275kV Lines (km)
7346
654
Total installed Transformer
MVA
123,995
65,325
Transformers 250MVA+
232
102
Transformers <250MVA
220
33
Reactive Power Capacity
Capacitors
91
18
Total installed MVAr
7,540
2,186
Reactors
60
49
Total installed MVAr
7,300
12,700
Source: Eskom
54.
Expansion of the transmission system is planned to accommodate the increased demand and
planned generation capacity. Eskom’s planning process identifies three distinct planning periods:
•
•
•
5 Year Supply Plan: Commitment of expenditures has already been made;
10 Year Transmission Development Plan: Projects in advanced planning with pending
commitments; and
20 – 25 year Horizon View: Evaluation of alternative scenarios of future grid requirements and
identification of robust strategy or least regret projects.
Figure 12: Transmission Strengthening Projects Planned in South Africa
95
55.
Overall Demand and Supply Balance: In 2007/2008, demand for electricity outstripped the
capacity of the supply system, resulting in frequent load shedding and a few blackouts. For example, in
mid-January 2008, nationwide power outages occurred and lasted approximately four weeks. The
reserve margin dropped to approximately 6 percent (see Figure 13 below), which is well below safety
limits (typically 15 percent). This lack of adequate power supply has affected the neighboring
countries, too. The impact of the global financial crisis on the South African economy has temporarily
increased the reserve margin to about 15 percent, but as the small business, industries, aluminum
smelters, mines and other large industries return to normal production, supply deficits will recur until
commissioning of the new power plants begins in mid 2012.
Figure 13: Demand-Supply Balance (1994-2007)
56.
As Figure 14 below shows, electricity elasticity (electricity/GDP) has been well-established
and electricity projections based on GDP are considered reliable.
Figure 14: Relationship between GDP and Electricity Demand for South Africa
Source: www.gsb.uct.ac.za/mir
57.
Figure 15 depicts various demand projections, which were the basis of Eskom’s generation
development process. The moderate growth is based on a moderate GDP growth forecast of 4 percent,
resulting in a 2.3 percent increase in MW capacity per annum. The higher growth is based on 6 percent
average GDP growth, resulting in 4 percent power demand growth.
96
Figure 15: Demand Projection for Power Supply
118400
108400
98400
Demand (MW)
88400
High
Moderate
78400
Moderate without smelters
Low
68400
58400
48400
38400
2008
2013
2018
2023
2028
2033
2038
Year
58.
While the GDP and demand forecast may have to be adjusted further as the global financial
and economic crisis unfolds, reserve margins are expected to remain low as shown by Figure 16
below.
Figure 16: Projected Demand and Generating Capacity Balance
Reserve Margin (Reliable Capacity)
25.0
Reserve Margin (%)
20.0
15.0
Reference
Policy-adjusted IRP
MYPD Capacity
10.0
5.0
0.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Years
D. Policy Making and Integrated Resource Planning for the Electricity Subsector
59.
As the country's economy continues to grow, energy is increasingly becoming a key focus.
The Department of Energy is responsible for ensuring development, processing, utilization and
management of South Africa’s energy resources.
97
60.





The DoE’s Energy Policy is based on the following key objectives:
Attaining universal access to energy by 2014;
Accessible, affordable and reliable energy, especially for the poor;
Diversifying primary energy sources and reducing dependency on coal;
Good governance, which must also facilitate and encourage private-sector investments in the
energy sector; and
Environmentally responsible energy provision.
61.
Energy Expansion Planning: The planning function for public investments in the energy sector
of South Africa is very robust. The DME performs Integrated Energy Planning (IEP) to identify future
energy demand and supply requirements. The National Electricity Regulator performs National
Integrated Resource Planning (NIRP) to identify the future electricity demand and supply
requirements. Similarly, Eskom continually assesses the projected electricity demand and supply
through a process called the Integrated Strategic Electricity Plan (ISEP).27 In mid 2009, the ISEP was
superseded by the Integrated Resource Plan (IRP), a tool formulated by the Department of Energy for
the electricity sector. Through these assessment and planning processes, the most likely future
electricity demand based on long-term Southern African economic scenarios is forecast, which
provides the framework for Eskom and the Government to investigate a wide range of supply- and
demand side scenarios and technological options to meet the needs of the sector.
62.
The Integrated Resource Plan (2009): The DoE estimates that electricity demand will grow at
an average of 2.4 percent over the next five years alongside an expected recovery in global and
national economic performance. To meet with the anticipated electricity needs, DoE, as the policy
maker for the electricity sector, commissioned in 2009 an update of the IRP for the electricity sector.
This IRP is akin to generation master plans. The impacts of electricity price increases are included in
this forecast, allowing for an increase in efficiency as high medium-term increases impact industrial
and other consumption patterns. Demand side management programs are also expected to reduce the
overall demand growth over this period.
63.
The demand growth is expected to taper off to a longer-term average of 3.2 percent over the
20-year planning horizon. The spurt from the recovery is expected to dissipate after 2014, while
efficiency improvements and a general switch from energy-intensive industries over time allows
economic growth to continue with reduced electricity demand growth.
64.
For the purposes of the IRP, Eskom is expected to continue with the current build program and
completion of the return-to-service program (RTS) of the previously mothballed coal-fired power
stations. In addition, the Renewable Feed-in Tariff program (REFIT), Medium Term Power Purchase
Program (MTPPP) and the open-cycle gas turbine (OCGT) independent power producer (IPP) are
expected to provide additional capacity in the medium term.
65.
From the demand side perspective, the IRP incorporates known demand side management
programs including commercial, industrial and residential, for a total savings of 23TWh by 2019.
66.
The least-cost reference expansion plan thus results in construction of coal-fired and nuclear
power stations to meet the demand over the planning horizon, with OCGT power stations providing
peaking energy. This outcome is not surprising given the relative low cost of coal-fired power stations
and high domestic reserves of coal to meet future demand as well as low cost of coal.
67.
While the reference plan indicates the least-cost alternative these costs do not include the
inherent externalities involved in coal-fired electricity production, in particular growing concerns
27
ISEP is a robust planning tool developed by Eskom that analyses and prioritizes the base and peak load capacity
requirements based on rigorous analyses of alternatives for supply under various demand scenarios. Based on detailed
analysis of each of the above aspects, the model compares the various generation capacity options and arrives at the optimal
mix for the power system.
98
regarding greenhouse gas emissions as well as a security of supply imperative in diversifying the
national energy base. However, the economic analysis (Annex 9) considers these externalities. The
Long Term Mitigation Strategy provides a firm target of emissions in 2025. Scenarios were developed
around these inputs, allowing for some regional shift in emissions and a potential delay in the
implementation of the emission ceiling until 2025. A number of scenarios were generated to cater for
emission constraints as well as the policy objective of increased private participation in the electricity
generation sector. These risk-adjusted scenarios were assessed based on criteria of cost, emissions and
diversity objectives, as well as discounting for additional risk to the system.
68.
Other policy adjustments included allowance for additional DSM projects (such as the million
solar water heater target), which brought the total DSM to the 23 TWh indicated above, a nuclear fleet
strategy, the inclusion of hydro capacity from the region and the advance of the Moamba gas-fired
option in Mozambique.
69.
The IRP is predicated on many assumptions regarding power generation technologies. These
include: early development and commercialization of renewable energy alternatives, in particular CSP,
which would allow it to be used as an effective mid-merit power source; the development of a nuclear
strategy to provide low emission baseload alternatives to coal-fired generation from 2020; continued
investment in the maintenance and refurbishment of existing Eskom (and non-Eskom) plants to ensure
generator performance at assumed levels; continued development of policies to attract IPPs in the
sector; and continued private/public sector investment in DSM to improve energy efficiency, thus
delaying capacity requirements.
70.
The final policy-adjusted IRP (until 2030) is being developed to meet the criteria of cost,
emissions, diversity and risk, and the policy requirements of the DoE. The current IRP focus is
primarily on generation and does not incorporate any long-term water usage constraints for power
generation. The nuclear power stations are planned to be located along the coasts, thus reducing the
freshwater requirement; other sources such as CSP and coal-fired generation are intensive water users.
These are being addressed through regional planning exercises and their outcome could influence the
IRP results. While the IRP does not address transmission needs directly, transmission planning is
carried out to complement the generation planning to ensure coordinated system development. Figure
17 provides an overview of new capacity additions by technology mix for the next 30 years. Figure 18
provides the projected energy generation from renewable energy resources in the near future.
Figure 17: New Capacity Additions Technology Mix (2009-28)
Net new capacity (2028)
Non-dispatchable
22%
Peaking - Pumped
Storage
4%
Baseload - Coal
39%
Peaking - OCGT
6%
Midmerit - CCGT
13%
Baseload - CCGT
2%
Baseload - Nuclear
14%
99
Figure 18: Projected Energy Production from New Renewable Capacity (2009-28)
Cumulative generation from Renewable sources (GWh)
Projected Renewable Production
12000
10000
8000
6000
4000
2000
0
2009
2010
MTPPP 1 (Biomass)
2011
2012
REFIT Wind
REFIT Other
2013
Sere
2014
Target
71.
Regional Electricity Expansion Plans: South Africa is part of the Southern Africa Power Pool
(SAPP) which connects the power systems of all countries of the Southern Africa sub-region (Angola,
Botswana, Lesotho, Malawi, Mozambique, Namibia, South Africa, Swaziland, Zambia, Zimbabwe),
and those of Tanzania and DRC. The SAPP is evolving and is the framework for the Bank’s power
sector development strategy in the sub-region. The total combined installed capacity of the SAPP is
about 51 GW; the available capacity has been only about 45.3 GW while demand has been growing
(more than 45.5 GW in 2007) at about 4 to 6 percent annually. South Africa (Eskom) is the largest of
the 12 SAPP members with about 80 percent capacity and about 82 percent of energy demand.
Mozambique is the second largest inter-connected member with an installed capacity of about 4.4
percent of the SAPP countries. As shown in Figure 19 below many SAPP countries are already
connected and these interconnections are proposed to be improved in the medium term thus laying the
foundations for electricity trade.
Figure 19: SAPP Transmission Network
72.
In the past, South Africa has provided electricity to many of the countries in the SAPP.
However, with the recent domestic supply constraints, it started curtailing electricity exports. South
100
Africa today imports electricity from Cahora Bassa hydro plant (1,200 MW) in Mozambique. As a
critical participant in the SAPP South Africa expects to sell and buy electricity to and from its
neighboring countries in the future. However, 9 of the 12 countries in SAPP have been experiencing
serious energy shortages, some more than the others. Table 5 below provides an overview of the
regional SAPP demand and supply balance in 2007.
Table 5: SAPP Existing Capacity, Peak Demand and Reserve Margin in 2007
Country
Botswana
Utility
BPC
Coal
Gas
Hydro
Nuclear
132
Total
% of
Total
Avail.
Capacity
Net
Peak
Demand
Surplus/
(Deficit)
Reserve
Margin
(%)
132
0.26%
120
563
(443)
n.a.
286%
Mozambique
EdM
64
2157
2,221
4.36%
2,075
537
1538
Angola
ENE
275
474
749
1.47%
590
897
(307)
n.a.
Malawi
ESCOM
245
245
0.48%
240
268
(28)
n.a.
South Africa
Eskom
n.a.
Lesotho
LEC
Namibia
NamPower
Swaziland
SEB
DRC
SNEL
Tanzania
TANESCO
Zambia
ZESCO
Zimbabwe
ZESA
35,625
108
342
24
2061
39,828
78.26%
36,208
36,720
(512)
72
1,800
72
0.14%
70
130
(60)
n.a.
240
372
0.73%
370
474
(104)
n.a.
n.a.
42
42
0.08%
40
204
(164)
2442
2,442
4.80%
1170
1,075
95
9%
563
561
1,124
2.21%
1024
772
252
33%
10
1752
1,762
3.46%
1630
1,643
(13)
n.a.
750
1,905
3.74%
1825
2,186
(361)
n.a.
100%
45,362
45,469
(107)
1,155
Total ( MW)
37,020
1,278
10,796
1,800
50,894
% of Total
by fuel type
CO2 (Mt)
72.7%
2.5%
21.2%
3.5%
100.0%
219.70
1.75
73.
The supply shortages in the SAPP region were aggravated by the crisis in South Africa as:
a. South Africa has a dominant and contagious effect on the rest of the SAPP. South Africa is the
dominant member of the SAPP and currently a net exporter to key countries (Botswana, Namibia).
South Africa’s troubles with generating adequate power quickly spread and affected the SAPP
countries.
b. Demand far exceeds available capacity. With little new capacity added, demand grew and far
exceeded available supply, thus eroding reserve margins. Eskom is unlikely to sustain exports to
SAPP countries; over the short- to medium-term (through 2015), countries currently importing
from Eskom (mainly Botswana, and also Namibia) will need to secure their sources of power to
replace the declining (and soon to cease) supplies from Eskom.
c. The rest of the SAPP is too small to handle the solutions alone. The available capacity in the
rest of the SAPP (about 9,000 MW) is not sufficient to cover large scale short-falls; the
transmission system and links are not adequate or flexible to transfer large amounts of power
flows. South Africa’s energy crisis has thus caused ripple effects in the SAPP, especially in
Botswana and Namibia.
d. Power trade is small. More than 95 percent of the energy in the SAPP network is consumed
within the producing countries and electricity trade is relatively small. Historically, net exports
(excess over imports) by Eskom were slightly over 1000 MWe (~2 percent), mostly to Botswana,
Namibia, Zimbabwe, Swaziland and Lesotho, based on bilateral contracts. A further small portion
of energy was traded in the short term market operated by SAPP; about 377 GWh, compared to a
demand of 1,118 GWh in 2007 (as reported by SAPP).
74.
Further dependence on imports and exports of power in the SAPP is key to long term self
sufficiency for electricity in the sub-region. The SAPP optimal expansion plan study carried out by the
101
Bank (through a PPIAF grant and undertaken by Nexant of USA) indicates that about 39,000 MW of
additional capacities are needed across SAPP through 2025, of which 22,000 MW (or 56 percent) is
for South Africa alone (see Table 6). A part of these new additions will replace about 12,000 MW of
old units, especially coal power plants. Based on this assessment, it is expected that:
a. South Africa will cease to be an energy exporter from 2012-13 onwards and instead
intends to import up to 16 percent of its needs from the rest of the SAPP.
b. DRC, Mozambique and Zambia could become energy exporters to SAPP by taking the
space given by South Africa.
c. Coal will remain the dominant energy resource (73 percent) and will continue to remain
so, albeit with a declining proportion, through 2020. Post-2020, other options such as
nuclear power in South Africa and hydropower in DRC will play a significant role, thus
helping the SAPP to significantly reduce its reliance on coal power.
d. Even though DRC has the largest hydropower potential of Africa, developing this
potential will require long lead times based on country issues and the long transmission
lines required through multiple countries.
e. A relatively modest amount of solar and wind energy will supply SAPP’s energy needs
and will require significant buy-down of costs (e.g., through feed-in tariffs, CTF, etc.).
Table 6: SAPP Optimal Expansion Plan (Cumulative MW; includes reserve margin)
Year
SAPP
2008
50,894
2010
54,874
2015
64,060
2020
71,621
2025
78,063
Source: Assessment of SAPP resources, Nexant 2009
Eskom
All Others
39,828
43,962
50,676
55,479
59,415
11,066
10,912
13,384
16,142
18,648
75.
In addition to electricity, South Africa also currently imports natural gas from Mozambique
through a 537-mile gas pipeline. The pipeline has a peak capacity of 524 MMcf/d of natural gas and
there are plans to double its capacity. Also, there are significant coal and coal bed methane resources
in Botswana, but it is uncertain when such resources will be developed, and whether power exports
from Botswana might be available. Feasibility work on development of the CBM resources is
underway. While developments of the hydro potential in DRC are difficult to predict and most likely
will take a long time, there are some prospects which have the potential to play a role in the
intermediate and long term – medium-term developments include two hydroelectric plants: Mphanda
Nkuwa (1,500 MW) in Mozambique and Kafue Gorge Lower (600 MW) in Zambia. The additions
(Table 7) are based on demand forecasts for the SAPP countries (2007-25) growing at an average
annual rate of about 2.9 percent, which is about equal to the historical rate of about 2.8 percent growth
during 1998-2006. The SAPP expansion plan of 39,000 MW includes 28 GW of thermal power plants
(coal and gas) and about 11 GW of hydropower plants, requiring about 11 new transmission
interconnections.
Table 7: SAPP Expansion plan to 2025 ( MW)
SAPP
South Africa
2009-2015
2016-2025
2009-2025
2009-2015
2016-2025
2009-2025
Thermal
15,500
12,500
28,000
9,200
9,600
18,800
Source: Assessment of SAPP resources, Nexant 2009
102
Hydro
6,000
5,000
11,000
2,300
1,000
3,300
Total
21,500
17,500
39,000
11,500
10,600
22,100
76.
The Electricity Pricing Policies and Tariff Regime: For the last several years, bulk electricity
tariffs were based on Eskom’s low depreciated asset base, valued at historical net book values and
little to no requirements for investment capital. During the 1980s and 1990s, Eskom’s tariff thus
steadily reduced in real terms, which means that electricity prices in South Africa became far lower
than in any other comparable countries and well below full “current” economic cost. The cost of
building a new fossil fuel power station is six to seven times that of the average cost of the existing
power station per megawatt of capacity. The South African economy is continually growing, resulting
in the need for significant investments in electricity infrastructure to meet continued growth in
demand. The GoSA is cognizant of the fact that this cost of new capacity (developed either by the
public or the private sector) will have to be reflected in the future pricing of electricity.
77.
The Government has developed a new “Energy Pricing Policy” (EPP) designed to guide the
sector towards long-term financial viability. This detailed and extensive document has gone through a
lengthy consultative process to ensure a broad base of stakeholder inputs, thus helping establish longterm support for this important initiative. The final version of the EPP was published in the
Government Gazette on December 19, 2008. The EPP establishes the principles for electricity pricing
levels, including provision of support for the poor, the process for establishing prices and the
responsibilities of NERSA for the issuance of rules needed to implement the pricing principles. Given
the considerable price adjustments that are expected to take place and the need to avoid problems
associated with tariff shocks, the program is expected to be implemented over the next five years.
Table 8 below provides an overview of bulk and retail tariffs charged by Eskom in 2008/2009 to
various consumers.
Table 8: Eskom Tariffs in 2010 (Rand/kWh) prior to February 24, 2010 MYPD228
Energy Charge (c/kWh)
Sector
Low Demand
Season or OffPeak
Notified Maximum Demand
Standard
High Demand
Season or OnPeak
Residential
Home Bulk
Multiple Housing Complexes
33.3
Home Standard
Urban Residential Customer
39.52
Home Light
Low Usage Urban Customers
45*
Rural
Ruralflex
> 25 kVA
16.45
Nightsave
> 25 kVA (three phase)
13.5
Landrate
< 100 kVA (High Voltage)
23.63
38.74
40.63
81.23
14.9
24.01
17.67
26.68
19.6
Urban
Nightsave
> 25 kVA
12.27
Megaflex
> 1 MVA
10.56
Miniflex
25 kVA to 5 MVA
10.43
Business Rate
< 100 kVA
17.26
33.63
* The energy rate is higher but there are no other connection, administrative or service fees.
78.
Since the establishment of NERSA, Eskom has submitted three applications for tariff increases
(under the MYPD regime). On June 25, 2009 NERSA approved an average tariff increase of 31.3
percent for Eskom effective July 1, 2009. This was considered an effective FY09/10 MYPD approval
with the expectation that second request would be submitted by Eskom later in 2009. In September
2009, Eskom submitted its MYPD2 application to NERSA requesting a 45 percent annual tariff
28
Currently under finalization by Eskom
103
increase for the next three years during FY10-FY13, which was within the pricing cone indicated by
NERSA in its approval of MYPD1. However, after extensive consultations with its stakeholders,
including the government, its high voltage customers, and feedback from the public, Eskom revised its
MYPD2 application and reduced its tariff increase request to 35 percent per annum for the next three
years in FY11-FY13. On February 24, 2010, NERSA completed review of MYPD2 application and
announced its decision to allow Eskom to raise tariffs by 24.8% in FY 2011, 25.8% in FY 2012 and
25.9% in FY 2013.
79.
Pro-poor Electricity Access and Tariff Policies: The GoSA entered into an important
electrification program as part of its post-Apartheid program designed to improve the distribution of
incomes. The program started in 1993 with electrification levels of 34 percent, and reached an 81
percent level of electrification by 2007. This is an unparalleled achievement in Africa, where most
countries are struggling to maintain prevailing electrification levels, and few other countries
worldwide have done so well. The year on year electrification rates have decelerated in the recent past,
as funding constraints have limited the sector’s implementation capacity. There is a risk that the
current financial crisis and possible supply shortages could further impact the success achieved. The
EPP includes three important components that help ensure success of the program, including support
for the poor: (a) accelerated access to electricity; (b) subsidized electricity for the poor; and (c) a projob strategy for economic growth supported by reliable, low cost electricity supplies.
80.
Enabling recently-connected poor consumers to afford the cost of electricity consumption has
been a central part of the GoSA electricity policy. In 2003, the Government launched the Free Basic
Electricity (FBE) policy. The FBE program, which is targeted at the poor, envisages provision of a
minimum of 50 kWh of free electricity per month. It is financed by the national government and
managed by Eskom and 185 distribution companies. The local government decides within each
respective municipality who qualifies for free basic services; the municipality provides the names of
the customers qualifying for FBE to the distribution agency, and the agencies (including Eskom) claim
back from the municipality each month the free allocations provided. The municipality in turn receives
the allowable funding from the GoSA. At present, the FBE covers approximately 3 million
households; 1.2 million of which are customers of Eskom (mostly in rural areas) and the remainder of
which are served through municipal distribution companies. The FBE system is supplemented by
cross-subsidies from large customers to households using less than 350 kWh/month. The FBE system
also extends to off-grid energy systems, largely solar home systems, intended to facilitate the provision
of basic lighting and media access. There are also other special reduced ‘life line tariff’ arrangements
for customers consuming less than 350 kWh/month. In addition, various municipalities also provide
additional benefits for the poor and low-income households as part of their own subsidy programs.
81.
An assessment carried out by the GoSA in 2005 indicates that a reasonable to low proportion
of annual incomes is spent on energy (including electricity, kerosene, fuel wood, gasoline etc.) in
South Africa. People living in the poorest areas spend about 19 percent of their income on energy;
those in peri-urban areas spend about 14 percent, and those in urban areas spend about 3 percent.
82.
The most important component of the pro-poor policy associated with electricity supply is the
need for electricity to support labor-intensive economic growth. South Africa’s unemployment rate is
estimated to be 23 percent, making it one of the largest socio-economic issues that the Government
needs to address. The load-shedding in January 2008 seriously affected households, small business,
industry and mines. The jobs lost associated with these closures as well as the negative impact on the
balance of trade prompted the President, in his State of the Nation speech in February 2008, to reemphasize the urgency of dealing with this problem. A National Electricity Response Team (NERT)
was established with responsibility for a focused energy efficiency program in addition to actions
already being taken by Eskom. The quick response to the problem limited the negative impacts to
economic growth, giving short-term respite until the global economic crisis hit in late 2008.
104
E. Proposed Restructuring of the Electricity Sector & Role of the Private Sector:
83.
Consistent with the GoSA strategy to rationalize the structure of the sector in order to increase
operational efficiency, enhanced private sector participation and renewable energy development, DoE
has taken a number of steps and issued enabling regulations. At the Apex level, DoE has undertaken
the development of the IRP, which provides the overarching framework for the electricity sector
development (see Paragraph 61). In parallel, the government is taking steps to create a single buyer
and independent system operator, which are expected to be endorsed by the Cabinet in the next few
months. It is expected that upon endorsement by the Cabinet, Eskom will create an independent
subsidiary as an Independent System Operator & Single Buyer. It is expected that the Electricity
Regulation Act will be promulgated in late 2010 before the ISO/Single Buyer can be divested as a
separate entity. Figure 20 below provides an overview of the proposed sector restructuring.
84.
It is expected that the ISO will be responsible for planning, procurement of IPPs, dispatch and
market aggregation. In this context, the MoF will also agree to guarantee PPAs signed by the ISO, on a
case by case basis as this entity is not expected to have an asset base and may not be seen as
creditworthy in the near term. This proposed restructuring and creation of a Single Buyer with MoF
support is expected to go a long way in giving comfort to the private sector to enter the sector and
mitigate part of the resource constraints it currently faces. The new regulation also provides for cost
recovery for private projects through the bulk tariff approved by NERSA. In the medium term, DoE is
also considering the creation of a transmission organization and restructuring of the distribution sector
(see paragraph 46).
Figure 20: Proposed Sector Reorganization
F. Electricity Sector & Climate Change
85.
The South African government ratified the United Nations Framework Convention on Climate
Change (UNFCCC) in August 1997 and acceded to the Kyoto Protocol (the enabling mechanism for
the convention) in August 2002. However; producing and distributing electricity has environmental
consequences that must be managed to ensure sustainable development. Eskom has clearly stated that
it is determined to play its part and is committed to accelerating efforts to address these challenges.
86.
South Africa has been active in the climate change policy arena for over a decade. Progress
has been slow, but momentum continues to grow. Eskom actively participates in various national and
105
international initiatives, including the Combat Climate Change (3C) initiative. This business leaders’
initiative aims to form a global opinion group consisting of companies that demonstrate leadership by
demanding an integration of climate issues into the world of markets and trade. Eskom also actively
participates in the World Business Council for Sustainable Development (WBCSD) and the
International Emissions Trading Association (IETA). Eskom is the co-chairman of the Electricity
Utilities workgroup under the WBCSD, an important platform that allows Eskom to talk to its industry
peers. In addition Eskom has partnered with World Wildlife Fund (WWF) of South Africa to stimulate
research into the renewable energy industry and joined the partnership to stimulate energy efficiency
through the signing of the South African National Business Initiative’s energy efficiency accord. 87.
Not many countries have adopted supercritical and CCS ready designs in their approach to
climate change and the reduction of CO2 emissions. However, South Africa has determined that all of
its new coal-fired-plants will be undertaken using more efficient technologies. This is in line with the
GoSA’s commitment on climate change and its adoption of CO2 abatement curves under the South
Africa LTMS. In addition, adoption of low-carbon technologies also is in line with the World Bank
Group’s Climate Change Strategy as well as the criteria for securing support from the Clean
Technology Fund (CTF).
88.
In order to moderate demand growth, Eskom, together with the DoE and NERSA, has
embarked on a DSM program aimed to save 3,000 MW of generation capacity by 2013 at a cost of
approximately R10 billion (US$1.25 billion). The EE/DSM programs represent the Government’s first
steps towards implementing its LTMS designed to deal with climate change issues.
89.
Although the Government does not expect RE to relatively contribute much to the energy mix
until 2013, it is taking steps to address barriers, such as by introducing feed-in tariffs and establishing a
suitable legal and regulatory framework. Whereas the White Paper on Renewable Energy (November
2003) sets a target to supply 4 percent29 of projected electricity demand for 2013 (below 2000 MW),
estimates show that with an enabling legal and regulatory framework and enhanced research and
development, local and regional renewable energy sources could contribute significantly to the
country’s energy mix over time. Figure 21 shows a “Progressive” RE scenario and Figure 22 shows
one for “Business as Usual.” Some of the SAPP countries such as Mozambique, Zambia and
Democratic Republic of Congo, have, with multilateral support (including from the World Bank
Group) initiated work on the development of medium- and large-sized hydroelectric power projects.
Expeditious development of these projects, the Bank’s proposed support and engagement with Eskom
are expected to move South Africa to a progressive RE scenario.
29
The target is likely to be raised in the revised White Paper in 2010.
106
Figure 21: Progressive RE Scenario Installed Capacity
Figure 22: Business as Usual RE Scenario Installed Capacity
Source: Banks D. and Schaffler J; 2006
90.
Eskom currently tracks and monitors greenhouse gas emissions and continues to improve the
accuracy and reporting of its greenhouse gas footprint. Emissions have been increasing over the last
decade due to the dominance of coal in South Africa’s energy mix and increasing demand for
electricity. Although no current restrictions apply to Eskom’s greenhouse gas emissions, a
comprehensive range of voluntary climate change initiatives has been pro-actively developed.
91.
Eskom’s climate change strategy, as approved by its Board, proposes immediate and longer
term (post-2012) action to reduce these emissions and adapt to the negative impacts of climate change.
The strategy ensures that climate change considerations are included in investment decisions; for
example, taking into account future carbon prices. The strategy was internationally peer-reviewed in
2006 and was judged to be best practice for addressing climate change, even when compared to
utilities in developed countries, given the resource constraints South Africa faces.
92.
Eskom’s overall future mix of energy solutions is intended to reduce its reliance on fossil fuels
while emphasizing the growing contribution of alternatives and demand side measures. Eskom’s
response to climate change is multifaceted and encompasses strategies to reduce emissions as well as
to adapt to the impacts of a changing climate, including:
107
a. Short- to medium-term initiatives focused on energy efficiency. Eskom has led the way
with its internal energy efficiency program, together with working with consumers to
reduce their demand and thus reduce all emissions, including carbon. This program (which
in the future is expected to be led by the Independent System Operator will build on
existing successes to significantly reduce future emissions through nationwide
deployment. More recently, measures to reduce emissions have included the DSM
program. Eskom has begun this process by seeking efficiency improvements in the use of
electricity. Savings will grow as the accelerated DSM program is rolled out in the years
ahead and the aims of the internal Eskom energy efficiency program are realized. The
program has achieved a CO2 emissions saving of 289 tons (2006: 271 tons). The climate
change strategy has mobilized, and will further mobilize, CO2 reduction mechanisms to
combat climate change.
b. Adaptation mechanisms are of special importance to Eskom as extreme weather events
severely affect the performance of wet-cooled power stations, transmission and
distribution infrastructure, line and thermal efficiency and the operation of hydro-electric
plants. The effect of changing rainfall patterns poses a particular threat to water
availability for power station operation. Some adaptation measures considered include the
consideration and adoption of dry cooling for new power stations (and retrofitting some
existing facilities), thus reducing plant water consumption by approximately 90 percent.
c. The diversification of South Africa’s energy mix is a medium- to long-term initiative,
which will result in significant cuts in emissions. The extensive deployment of renewable
energy resources will form the basis for long-term cuts in greenhouse gas emissions.
Eskom is committed to diversifying its energy mix, though it recognizes that South Africa
will be dependent on coal for the foreseeable future. Diversification therefore entails a
long-term effort to harness a variety of new and existing technologies. To remain alert to
future opportunities, Eskom is developing technology roadmaps that identify new
technologies and predict when they will be ready for implementation. The coal technology
roadmap was the first of the roadmaps to be initiated.
108
Annex 2: Major Related Projects Financed by the Bank and/or other Agencies
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Sector Issue
Ratings
(Bank-financed projects only)
Project
IEG Ratings
Completed Projects
None in South Africa
Outcome
Risk to
Development
Outcome
Borrower
Performance
None in South Africa
OED Ratings
Outcome
None in South Africa
Sustainability
ID Impact
None in South Africa
Latest Supervision (ISR) Ratings
Ongoing Projects
Removing barriers to, and reduce
the implementation costs of,
renewable energy technologies to
help mitigate greenhouse gas
emissions from grid based
projects.
Renewable Energy Markets
Transformation Project (GEF only)
Improvement of ecosystem
functioning of the Lake St Lucia
and Umfolozi River System.
Development, Empowerment and
Conservation in the Greater St
Lucia Wetland Park and
Surrounding Region Isimangaliso Wetland Park (GEF
only; first use of UCS for
Safeguards)
Implementation
Progress (IP)
Development
Objective (DO)
U
MS
NA
NA
Other Development Agencies
European Investment Bank
Loan Facility to finance 765 kV transmission lines (2009)
Japan Investment Cooperation
Agency
Loan Facility to finance energy efficiency (proposed 2010)
African Development Bank
Loan Facility to finance the 4800 MW Medupi Power Plant (2009)
Agence Française de
Développement
Loan Facility to finance the Sere Wind Power Plant (as a restructuring of an earlier
loan facility) (proposed 2010) & a credit facility through commercial banks in South
Africa to finance renewable energy and energy efficiency projects.
Euler Hermes
Kreditversicherungs-AG
Loan Facility Coverage to the Boiler Contract of the 4800 MW Medupi Power Plant
(2009)
KfW Bankengruppe
Loan Facility Export Risk Cover for the Turbine Contract of the 4800 MW Medupi
Power Plant (2009)
109
Annex 3: Results Framework and Monitoring
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Results Framework
PDO outcomes
(a) Increased reliable power
generation
(b) Increased renewable energy
supply
(c) Reduction in carbon intensity
Intermediate Outcomes
Project Outcome Indicators
 Installed capacity ( MW) as a
percentage of peak demand.
 Energy supply from renewable
sources.
 Carbon emissions discharged
per unit of electricity
(kg/kWh.)
Intermediate Outcome Indicators
Use of Project Outcome
Information
 Gauge level of energy supply
security.
 Determine if new investments
are contributing to a reduction
in carbon emissions.
Use of Intermediate Outcome
Monitoring
Component A: Construct the
Medupi coal-fired power plant
using supercritical technology
 Capacity (MW) of
conventional generation
constructed.
 Gauge contribution of new
capacity to energy security.
Component B: Construct
renewable energy-based power
plants:
 Capacity (MW) of renewable
generation constructed.
 Direct GHG emissions avoided.
 Gauge increase of clean energy
sources in the energy mix.
 Gauge increase in private
financing for renewable
projects.
 Coal transportation cost for
Majuba Power Plant.
 Reduction in carbon emissions
from coal transportation.
 Guidance for power plant
efficiency improvement.
 Guidance for development of
identified renewable projects.
 Guidance for development of
identified energy efficiency
projects.
 Gauge extent to which the
conversion reduces cost and
carbon emissions.
 Enable implementation of
supply-side efficiency
improvements.
 Enable implementation of
identified renewable projects
and associated infrastructure.
 Enable implementation of
identified energy efficiency
projects.
 B.1 - 100 MW Sere Wind Farm
 B.2 - 100 MW Upington CSP
Component C: Supply-side Energy
Efficiency and Technical
Assistance:
 C.1 - Convert Majuba coal
transportation mode from road
to rail (Majuba coal
transportation mode converted
from road to rail)
 C.2 - Provide technical
assistance for improving power
plant efficiency for the Eskom
Fleet and ( Improved power
plant efficiency for the Eskom
Fleet)
 C.3 - Provide technical
assistance for development and
implementation of domestic and
cross-border renewable and
energy efficiency projects
110
Arrangements for Results Monitoring
Target Values
Project Outcome
Indicators
Baseline
Installed capacity (MW)
as a percentage of peak
demand
Data Collection and Reporting
2010
2011
2012
2013
2014
2015
Frequency
and Reports
Data
Collection
Instruments
Responsibility
for Data
Collection
118%
117.7%
119.6%
121.7%
124.1%
126.8%
124.6%
Annual
Annual
report
Eskom
11GWh
11GWh
11GWh
11GWh
150GWh
230GWh
520GWh
Annual
Annual
report
Eskom, DoE
0.968
0.965
0.964
0.963
0.962
0.960
0.950
Annual
Annual
report
Eskom
Capacity ( MW) of
conventional generation
constructed
None
-
-
Unit 6 (800
MW)
Unit 5&4
(1600 MW)
Unit 2&3
(800 MW)
Unit 1 (800
MW)
Quarterly
Project report
Eskom
Capacity ( MW) of
renewable generation
constructed
None
-
-
-
100 MW
100 MW
200 MW
Quarterly
Project report
Eskom
0.238 MT
at
US$87/ton
of CO2
0.618 MT
at
US$97/ton
of CO2
Annual
Project report
Eskom
Energy supply from
renewable sources
Carbon emissions
discharged per unit of
electricity (kg/kWh)
Intermediate Outcomes
Direct GHG emissions
avoided - x million tons
of CO2 per year at US$
y per ton
None
-
-
-
0.238 MT
at
US$87/ton
of CO2
R93/ton
-
-
-
-
R20/ton
R20/ton
Annual
Annual
report
Eskom
Reduction in Carbon
emissions from coal
transportation
None
-
-
-
-
40,000 ton
40,000 ton
Annual
Annual
report
Eskom
Guidance for power
plant efficiency
improvements
None
Quarterly
Project report
Eskom
Majuba coal
transportation cost
Designs for
first 3
plants
Designs for
first 3
plants
111
Target Values
Project Outcome
Indicators
Guidance for
development and
implementation of
domestic and crossborder renewable and
energy efficiency
projects
Data Collection and Reporting
2012
2013
2014
2015
Frequency
and Reports
Data
Collection
Instruments
Responsibility
for Data
Collection
Review of
Alternatives
for
Configurati
on of TLines for
Renewable
and Cross
Border
Projects
-
-
-
Quarterly
Project report
Eskom
Baseline
2010
2011
Local
Capacity
Assessment
Finalization
of Bidding
Docs for
CSP
None
Review of
Alternatives
for CSP
Support to
develop
institutional
arrangemen
ts for
demand
side
managemen
t
112
Annex 4: Detailed Project Description
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
1.
The proposed Project consists of the following three main components:



Component A consists of Medupi coal-fired power plant (4,800 MW, based on
supercritical technology) and is expected to cost US$12.047 billion1, of which IBRD
will provide financing of about US$3.04 billion. This loan will be provided against
supply & install and civil construction contracts for (i) the power plant and (ii)
associated transmission lines.
Component B consists of investments in renewable energy (100 MW Sere Wind
Power Project and 100 MW Upington Concentrating Solar Power Project). This
component is estimated to cost US$1.228 billion, of which IBRD will provide
financing of about US$260 million.
Component C consists of both sector investments and technical assistance to support
lowering Eskom’s carbon intensity through energy efficiency and development of
renewable energy. The Majuba Rail Project (shift in transportation mode from road to
rail) and technical assistance for assessing the opportunities for coal-fired power plant
efficiency improvements and for implementation of the Upington CSP are envisaged
under this component. This component is estimated to cost US$576.07 million of
which US$440.77 million will be financed by IBRD.
Detailed Project Description
Component A: Medupi Power Plant
2.
Plant Location and Layout: The proposed Medupi Power Plant is being developed as a
greenfield coal-fired baseload power plant project with a gross installed capacity of 4,800 MW, in
Lephalale, a northern province of South Africa. The plant is expected to have a net capacity of 4,332
MW resulting in an annual energy generation of 3,200 GWh at an average load factor of 84.2 percent,
with a planned load factor of about 90 percent in the early years of operation. The power plant terrace
requires an area of approximately 700 hectares (ha) and an additional 1,000 ha is expected to be
required for ancillary services, including ash service facilities. The power station structure would be
approximately 130 m long and approximately 500 m wide.
3.
Technology: The proposed project is based on a supercritical design for boilers, which are able
to operate at higher temperatures and pressures than subcritical boilers, and thus operate with greater
efficiency.2 The feasibility phase of the project considered both sub- and supercritical pulverized fuel
technologies for implementation and concluded that the supercritical option was the preferred
technology solution. This is the first plant in the Eskom coal fleet to use supercritical design for
boilers, and is consistent with the GoSA low-carbon strategy (higher efficiencies in power supply).
1
The estimated total cost includes Interest during Construction directly related to debt that has been raised by Eskom for the
Medupi Power Plant. Any Eskom funding costs for its contributions to the plant from the Balance Sheet have not been
included and have been considered as Eskom equity to the project.
2
The term “supercritical” refers to the critical transition point of water to steam at pressures over 22 MPa. Supercritical units
typically refer to main steam conditions of 24 to 30 MPa and 538 to 600 ºC, with a single reheat stage at 566 to 600ºC. The
supercritical boiler is a once through design which (with sliding pressure) means that heating, evaporating, and super-heating
of the incoming feed water are completed within a single pass through the evaporator tubes and therefore does not require the
use of a steam drum to separate and re-circulate water during normal operation. The benefits of supercritical technology
include increased gross efficiencies. This technology provides improved cycle efficiency and hence improved environmental
performance. This increase in efficiency results in a reduction in coal consumption of approximately 5 percent as well as a
reduction in emissions in the order of 5 percent.
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4.
The proposed Medupi Power Plant will use the pulverized fuel (PF) technology, where coal is
first pulverized, and then blown into a furnace where it is combusted at high temperatures. The
resulting heat is used to raise steam, which drives a steam turbine and generator. The proposed
supercritical combustion will result in the new power station’s thermal efficiency being up to 37.5
percent (compared to approximately 34 percent for older power stations), resulting in a reduced
environmental impact as less coal will be burnt to produce the same amount of energy. The
boiler/turbine units are expected to be operated in the baseload operating regime for approximately the
first 20 years of the plant life. The power station is designed to be dry-cooled, because of the limited
water supply in the Lephalale area. This technology is less water intensive than power stations
utilizing conventional wet-cooling systems.3 The proposed Medupi Power Plant will be the largest drycooled power station in the world.
5.
Emissions Control Systems: The proposed power station will be fitted with low turndown
burners to improve the ignition and flame stability over an extended load range. The power station will
be a zero liquid effluent discharge station; particulate emissions will be controlled through the use of
fabric filters, and nitrogen oxides through the use of low-NOx burners. These emissions will be further
diluted through construction of exhaust stacks approximately 220 m in height.
6.
Due to the sulfur content of the coal (1.4 percent by weight) and the large scale of the plant,
sulfur dioxide emissions could have a significant adverse environmental impact when combined with
other existing and planned sources of emission to the affected airshed. Accordingly, sulfur dioxide
emissions will be removed using Flue Gas Desulfurization (FGD) technology. Studies conducted by
Eskom have indicated that wet FGD (a gypsum process) is the preferred sulfur abatement/reduction
technology based on an assessment of life cycle costs. Eskom has identified possible sources of
calcium for the proposed power station. The source of limestone has been located at Kraalhoek and
Dwaalboom, some 180 kms from Lephalale. All regulated emissions will be subject to continuous instack monitoring and ambient air monitoring stations will be sited in affected areas in cooperation with
DoEA.
7.
Coal Supply: The power station will source coal from the coalfields located about 3 kms north
of the plant. The Grootegeluk Colliery, which also services the existing Matimba Power Station, is
located to the immediate west of the plant. Situated 25 km from Lephalale in South Africa’s Limpopo
province, Grootegeluk is an open-pit mine that employs 1 800 people and produces 18,6Mtpa of
thermal and semi-soft coking coal using a conventional truck and shovel operation. The mine has a
5,559 million ton of raw coal resources (4,177 million ton measured, 1,347 million ton indicated and
96 million ton of inferred), from which semi-soft coking coal, thermal coal and metallurgical coal can
be produced. The mine is considered to be one of the most effective and lowest coal producers in the
world.
8.
Grootegeluk has the world’s largest beneficiation complex where 7,600 tonnes per hour of
run-of-mine coal is upgraded in six different beneficiation plants. About 15.3Mt of annual production
is power station coal, transported directly to Eskom’s Matimba power station on a 7 km conveyor belt
in terms of the existing supply contract. An additional 1.5Mtpa of metallurgical coal is sold
domestically to the metals and other industries on short-term contracts. Grootegeluk produces 2.7Mtpa
of semi-soft coking coal, the bulk of which is railed directly to Mittal SA under a long-term supply
agreement. Approximately 1.1Mtpa of semi-soft coking coal and thermal coal is exported through
Richards Bay Coal Terminal or sold domestically.
3
The dry cooled systems currently used in other Eskom plants utilize <0.2 l/kWh (liters of water per unit of electricity
generated), which equates to approximately 3 million cubic meters of water per year for a typical 2,100 MW installed power
station. In comparison, wet cooled systems currently used in some of the plants utilize approximately 1.8 l/kWh, which
equates to approximately 27 million cubic meters of water per year for a typical 2,100 MW installed power station. Therefore,
water usage is reduced from approximately 2.0 to approximately 0.1 – 0.2 liters per kWh of electricity generated by using
non-evaporative cooling techniques.
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9.
On September 19, 2008, Eskom signed the Medupi Coal Supply and Off-take Agreement
(CSA) with Exxaro Coal Limited (a private sector company). The expansion of the Grootegeluk
beneficiation plants to supply Eskom’s Medupi power station with 14.6 Mtpa of power station coal for
40 years, is progressing in line with the planned schedule to supply the first coal during the last quarter
of 2011. Full production from 2014 onwards is envisaged. The beneficiation expansion investment is
estimated to cost about US$1.25 billion and is in the detailed engineering design phase. The
development is aligned with Eskom’s request for proposals for independent power producers for baseload power stations.
10.
The coal from the mine will be supplied by overland conveyors and stored in a stockyard
adjacent to the terrace area of the station. The coal used by the plant is expected to have a calorific
value (dry basis) of 20.5 MJ/kg, ash content (dry basis) 35 percent, volatile matter 23 percent, sulfur
1.4 percent, total moisture 8 percent, and abrasiveness of 150 Mg/Fe. Eskom is currently in discussions
with Exxaro to finalize discussions regarding cost savings under the CSA. The mine is being
expanded by Exxaro in full compliance with South African legislation and policies pertaining to
environmental and social safeguards.
11.
Coal Conveyor Infrastructure: Conventional conveyor systems will be used for transporting
the coal from the mine to the stockyard at the plant. The length of the conveyor system is expected to
be 9.6 kms. The stockyard conveyor system is expected to provide a continuous throughput capacity of
2,000 tons per hour. The system is designed to be fully automated. All maintenance parts of the coal
conveying system are designed to minimize wear in order to achieve a service life of at least five years
continuous operation.
12.
Ash Conveyor and Disposal Infrastructure: Ash produced by the generating units will be
disposed of on a typical dry ash dump facility. Ash will be conveyed to the dump by the ash conveying
system and deposited on the dump by the stacking and spreading system. The dump facility will have a
drainage system, erosion protection, dust suppression system, top soiling and rehabilitation operation
and a road network. The system is being designed to be fully automated.
13.
Eskom has undertaken studies for the designated ash dump site layout and has simulated
future (50 year horizon) impact during construction and operation of the proposed power plant. Based
on this assessment, Eskom has indicated that for the first thirty years, the identified site (farm
Eenzaamheid) will be sufficient for ash disposal. Beyond the thirty year horizon, Eskom is expected to
dispose of ash by ashing back into the pit at the Grootgeluk mine. Ashing in the pit would lengthen the
life of the ashing facility proposed for the new proposed power station.
14.
Associated Transmission Lines: The transmission system being developed to evacuate
electricity from the Medupi Power Plant to the electricity grid includes approximately 2,244 km of 765
kV and/or 400 kV transmission lines. Currently, the plans include:
a. 3 x 400 kV power lines, i.e., 2 x 270 km power lines from the new power station to the
Dinaledi substation (via Spitskop) and 1 x 270 km power line from the new power station
to the Marang substation.
b. 4 x 400 kV from the new power station to a new substation (Delta).
c. 6 x 765 kV power lines from the Delta Substation to the Mercury substation (possibly
initially operated at 400 kV).
d. Overall, five 400 kV substations will be needed to integrate Medupi into the national grid
(including two green field substations).
15.
Associated Water Infrastructure: Water pipelines will be required for the provision of potable
and raw water. It is proposed that the potable and raw water be piped from the existing Matimba
Power station (or existing water supply pipelines located close by) to the new site along the existing
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ash conveyor servitude, along a section of provincial road and to the new proposed site. The proposed
water pipeline is approximately 5 km in length and will traverse Eskom owned land for the majority of
its length.
16.
Plant Construction Schedule: The first unit will be commissioned by the first quarter of 2012,
with the last unit scheduled for commissioning by the end of 2015.
17.
Operations and Maintenance Matters: The power station will have only one control room.
The outside plant, electrical system and units will be operated from there. The design is such that it
limits the amount of on load plant inspection, with maximized data recovery through the control and
instrumentation system. The control room is sized and designed to allow staff interaction during
incidents and plant start-ups. Access to the panel will be limited to operating staff, with other staff
capable of viewing operating parameters during critical operating periods from a separate non active
screen that can be selected to view any unit and parameter.
18.
The plant is being designed to facilitate efficient inspection, cleaning, maintenance and
repairs. All equipment for each unit will be identical and interchangeable.
Component B: Renewable Energy Investments
19.
This component consists of the following two subcomponents:
a. A 100 MW Wind Power Plant at Sere; and
b. A 100 MW Concentrating Solar Power (CSP) Energy Facility at Upington.
20.
Component B.1 — Sere Wind Power Project: The scope cosists of design, procure, construct
and commission a 100 MW wind power project and associated transmission lines and substations at
Sere in the Western Cape Province in South Africa. The proposed design is a two phase development
of wind turbines in the Province. Phase one (proposed subcomponent) comprises about forty to fifty
Class 2A wind turbines with a total generating capacity of 100 MW, and an expected annual
generation of about 219 GWh with a load factor of about 25 percent. In addition, transmission lines
and substations will be constructed to allow other renewable projects in the area (specifically under the
REFIT IPP program) to connect to the grid. Along with the second phase of development (not a
subject of this loan proposal), the facility is expected to have a total generating capacity of 200 MW
with about 100 turbines. The project is fully scoped and specified, and an environmental impact
assessment (EIA) has already been approved. Cumulative emissions savings from Phase 1 of the
Western Cape Wind Energy Facility (the Sere Wind Power Project), based on an annual output of 219
GWh, would be 5 million tons of CO2 over the 20-year life of the plant.
21.
Wind power has considerable potential for scale-up at an estimated 4 GW of economic wind
potential – mostly along the East and West coasts of South Africa. The avoided annual GHG emission
reductions in the hypothetical case of replication of the project throughout South Africa could
therefore be in the order of 10 million tons of CO2. Assuming that half of the available economic
potential for wind power is developed by 2025, the emission reductions would be about 5 million tCO2
or 1.4 percent of the overall reductions consistent with the GoSA long-term 40 percent reduction
target.
22.
Even though wind power technology is well proven and major components are commercially
available from multiple suppliers, the lack of proven performance on a large scale in South Africa
creates a perception of high risk. Furthermore, performance risk (e.g., annual output) is real and
remains despite intensive wind measurement. Finally, Eskom faces significant investments in
transmission infrastructure, driven mostly by the need to evacuate wind power and deliver it to load
centers and the main grid. Investments in transmission capacity to connect Independent Power
Producers (IPP) to the grid would catalyze substantial private sector investment in wind power. The
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Sere facility, together with new transmission capacity to evacuate its power, would be a flagship
investment in the subsector. In addition, investments in transmission capacity would catalyze
substantial private sector investment under the REFIT program.
23.
Wind Plant Components: The proposed site is in a remote location but has good access owing
to the existing road network providing access to the farming and mining areas. An existing divisional
road provides direct access to the site. This road surface will require improvement including surface
redesign and resurfacing with a suitable wearing course gravel to ensure an improved driving surface.
A number of surveys have been conducted and the following are expected to be carried out before
construction:




Geotechnical survey to provide information regarding subsurface characteristics for
founding conditions and road building;
Wind power plant facility site survey and confirmation (and pegging) of the turbine micrositing footprints, lay down areas and access road routes;
Survey of substation site; and
Survey and profiling of power line servitude to determine specific tower locations.
24.
The turbines and associated infrastructure are proposed to be positioned over an area of less
than 20 square kilometers. The proposed plant will include:
(i)
40 to 50 wind turbine units with an expected hub height of ~ 80 m (78 m high steel tower
plus 2 m high nacelle); 90 m diameter rotor (consisting of 3x45 m blades).
(ii) A concrete foundation (of 15 m x 15 m) to support each turbine tower with underground
electrical cabling between each turbine and the substation.
(iii) A substation (with a footprint of 80 m x 80 m) in an appropriate position to receive
generated power via underground distribution cabling from each wind turbine.
(iv) Other substations and transmission lines (132 kV) that allow for other renewable projects
in the vicinity (as a shared transmission system) to connect to the main grid.
(v) Internal access roads providing access to each wind turbine site (with a permanent travel
surface of approximately 6m in width).
(vi) Other associated infrastructure including office/workshop buildings with a footprint of
~400 m2 under roof.
25.
Wind Resource and Plant Layout: The site has a “moderate” wind resource, and is expected to
have a load factor of about 25 percent. A site layout optimization exercise undertaken by Eskom has
been used to identify the best possible positions for the turbines, as well as the substation and other
infrastructure from a technical perspective. An east-west optimized layout is proposed to maximize the
utilization of the prevailing SSW winds. The site layout includes the 40-50 turbines (with the potential
to include additional 40-50 turbines) in four rows which lie parallel and equidistant to one another. The
first turbine rows lie approximately 2 km inland from the coastline. This is to minimize wake effects
and wind turbulence. The positioning/layout of all the components of this wind energy plant have a 90
percent confidence level, and will be confirmed through the results of the surveys mentioned above.
26.
Associated Transmission Lines: The site is near a 132 kV sub-transmission line with sufficient
capacity to evacuate the power. An overhead 132 kV power line will connect the substation at the
wind energy site to the electricity distribution network/grid at the Juno Transmission Substation
(outside Vredendal). The connection point to the Eskom power grid has been confirmed through a
network planning exercise. Additional power line servitudes will follow other existing linear
infrastructure (including roads and/or other power lines) as closely as possible to consolidate linear
infrastructure in the area, and to minimize the need for additional points of access. The power lines
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will be constructed utilizing a monopole structure/tower with stand-off insulators and will be
approximately 25 m in height. The power lines will be double circuit (i.e., two 132 kV circuits carried
by a single tower structure), and will require a right of way of approximately 32 m in width.
27.
Component B.2 — Upington Concentrating Solar Power (CSP) Plant: The scope of the
proposed project is to design, procure, construct and commission a 100 MW CSP plant at Upington in
the Northern Cape Province. When operational, it is expected to be the largest concentrating solar
power power facility with heat storage for grid use, which will operate at partial baseload. The
estimated cumulative emissions savings resulting from a projected annual energy production of 516
GWh is 9 million tons of CO2 equivalent over a projected twenty-year plant life.
28.
Solar Resource in South Africa: The only renewable energy resource that can provide the
volumes of firm capacity to partially complement the capacity provided by coal-fired power plants is
CSP configured with thermal storage. This configuration has a load factor high enough to be
considered at least as a partial baseload resource. Northern Cape Province was identified as the most
feasible locality for the establishment of the CSP plant. It has one of the highest solar potential values
in the world, with a Direct Normal Insolation (DNI) level of approximately 2,900 kWh/m2 per year
(see Figure below). The design reflects a synthesis of design elements meant to reduce risk, improve
performance, maximize local content, and conform to local requirements.
Figure 1: South Africa – Distribution of Annual Solar Radiation
29.
CSP is an evolving technology with a number of innovative developments taking place
globally. Prior to undertaking the implementation of the CSP plant, Eskom plans to conduct a detailed
review of the CSP related development work already undertaken, including the proposed technology,
current design and proposed size in order to: (a) validate the proposed design; (b) optimize the plant
size and design in light of the current technological developments; and (c) incorporate any new and
feasible design features based on global state of the art. Based on this review, detailed deisgn of the
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plant will be undertaken followed by preparation of the bidding documents for engineering,
procurement, and construction of the plant. The proposed loan will also support the supervision of the
CSP plant construction and technical assistance during the initial years of operation. Considering the
vast solar resources in South Africa, feasibility analysis will also include an assessment of the
manufacturing capacity for some of the key components of the CSP plant. This work is expected to
enable the formulation of a domestic capacity development strategy in South Africa, considering the
sub-regional needs, the manufacturing potential and the remote location of the sub-region from the
traditional manufacturing establishments for such equipment.
30.
The demonstration and replication potential of CSP plants in Southern Africa is vast. In South
Africa alone, where the DNI levels range from 1.7 to as much as 2.9 MWh/m2/year, estimates are that
30 - 38 GW of commercially viable CSP could be developed – mostly in the Northern Cape and North
West provinces. Furthermore, potential replication in Namibia and Botswana could double or treble
this potential. The avoided annual GHG emission reductions in the hypothetical case of replication of
the project throughout Southern Africa could therefore be in the hundreds of millions of tons of CO2.
By the year 2025, assuming successful implementation and replication of the current project, CSP is
expected to generate emission reductions of about 40–80 million tCO2/year or about 10–20 percent of
the overall reductions required to achieve a level of emissions 40 percent below the current trend.4
31.
CTF support will have the transformational effect of promoting CSP deployment, particularly
in the private sector, by proving the technology in actual operation and establishing benchmarks for
cost and performance at utility scale. A number of private companies are currently engaged in
preliminary development work which could involve CSP and other solar technologies. DoE, in its
efforts to mainstream solar development including the concept of solar parks, is being supported by
various institutions including the Clinton Foundation.
32.
Even given the favorable REFIT tariffs, the deployment of CSP technology in South Africa is
currently a tall order for the private sector. Without Eskom’s participation, it is highly unlikely that the
private sector will go through with a similar investment in the near future. The participation of the
national power utility in the first commercial-size CSP project will increase the visibility of CSP and
renewable energy in general, and signal to the market that the GoSA sees it as a desirable and viable
alternative to coal-based electricity. For its part, the Upington project will have an important role in
helping Eskom move beyond coal in its operations.
33.
Solar Plant Components: The proposed Upington Concentrating Solar Power plant is a 540
MWt tower and mirror design, configured to operate as a partial baseload unit. Utilizing molten salt as
a thermal circulating fluid and storage medium is expected to allow this design to achieve a 60–65
percent annual load factor with a rated capacity of 100 MWe.
34.
The CSP technology considered for the proposed plant is a molten salt-type, Central Receiver
technology. It is based on the concept of thousands of large two axes tracking mirrors (known as
heliostats) which track the sun and reflect the beam radiation onto a common focal point. This focal
point (the receiver) is located on a tower well above the heliostat5 field in order to prevent interference
between the reflected radiation and the other heliostats. Heliostats are arranged in an elliptical
formation around the focal point with the majority of the reflective area weight to the more effective
side of the heliostat field (southern side in South Africa). It is estimated that approximately 6,000
heliostats at 120 m2 each will be required within the heliostat field in order to obtain a power output of
4
This estimate assumes that 10–20 GW of CSP capacity is installed in the country by 2025, and that the current (business-asusual) trend would lead to annual emissions of 870 million tCO2 by that year. A reduction by 40 percent from that level is
consistent with the goal declared by South Africa in Copenhagen to cut its emissions by 42 percent by 2025. The level of
reduction of 40 million tCO2 per year is relatively conservative for the 10 GW level of installed CSP capacity as it assumes a
relatively low annual load factor of 0.4.
5
A heliostat is a mirror mounted on an axis by which the sun is steadily reflected onto one spot.
119
approximately 100 MW, while also enabling approximately 8 hours of energy storage. The central
tower will be roughly 150 m to 200 m high for a 100 MW facility, with the central receiver taking up
the top part of the structure. This receiver is in essence a heat exchanger consisting of thin walled
tubing which absorbs the concentrating beam radiation and transfers the heat to the working fluid (the
molten salt circulated through it) which in turn is used to generate steam. Electrical power is then
generated through a Rankine cycle (steam turbine process).
35.
The working fluid is a salt mix of a 60:40 ratio of Sodium Nitrate (NaNO3) and Potassium
Nitrate (KNO3). The fluid is a very safe and environmentally friendly substance which is a solid at
room temperature. The cold salt is pumped up the central tower at approximately 300°C and flows
through the central receiver where it is heated to approximately 600°C after which it can be stored for
use in the conventional steam power generation process. One MWh requires approximately 5 m3
(roughly 10 tons) of stored hot salt.
36.
The proposed power plant is envisioned to utilize a dry cooling technology as a result of
unavailability of water in the proposed area. Dry-cooled technology reduces the total amount of water
consumed at power stations when compared to conventional wet-cooling. According to current design
specifications, the dry-cooled station would still need approximately 200,000 cubic meters of water per
year. The water pipelines as well as the overhead power lines will follow other existing linear
infrastructure (existing roads) as closely as possible to consolidate linear infrastructure in the area, and
to minimize the need for additional points of access.
37.
Associated Transmission Lines: The proposed Upington site is near a 132 kV sub-transmission
line with sufficient capacity to evacuate the power. An overhead 132 kV power line will connect the
substation at the facility site to the nearest substation. The overhead power lines will follow other
existing linear infrastructure (existing roads) as closely as possible to consolidate linear infrastructure
in the area, and to minimize the need for additional points of access.
Component C: Low carbon Energy Efficiency Investment and Technical Assistance:
38.
This component consists of the following two subcomponents:
a. The Majuba Rail Project; and
b. Technical Assistance to support Eskom for rehabilitation of existing coal-fired power
plants to improve operating efficiencies and for the development and implementation of
domestic and cross border renewable and energy efficiency projects.
39.
Component C.1 — Majuba Rail Project: This component includes the design, procurement,
construction and commissioning of the Ermelo to Majuba railway line that will become the main coal
transport system to the Majuba power station. The Majuba Power Station (currently operating at 85
Plant Factor) is a baseload plant. By the introduction of a heavy haul railway line at Majuba, it is
anticipated that 100 percent of the Majuba Power Plant’s capacity can be generated from coal supplied
via this line in the future, which has not only a financial benefit (less cost to transport coal) but also
multiple environmental and other strategic benefits (including freeing up capacity in the general freight
railway to supply coal to Tutuka Power Station).
40.
The proposed coal transport project between Ermelo and Majuba is a 68 km private siding
railway link connecting a take-off point located 8 km west of Ermelo on the Transnet Freight Rail (the
public transport utility of South Africa) coal export railway line to the existing Majuba Power Station
rail siding and tippler (see Figure 2 below). The proposed project will also include a new rail yard
layout to ensure an off-loading rate of up to 14Mtpa, and excludes modifications to the existing
Majuba Coal Stockyard System.
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41.
The proposed railway infrastructure consists of a 26-ton/axle single track (with 2 long passing
loops of 1.92 km each) designed for the operation of 100 wagon train lengths with 3kV-DC
electrification and signaling compatible with the existing Transnet standards on the Transnet Freight
Rail coal export railway line. The rail servitude (including 44 farm portions) has already been acquired
in accordance with the land acquisition plan, has been fenced, and service access will be provided
along the entire length of the rail route. Bridges (rail-over-river, road-over-rail, rail-over-road and
landowner access structures), culverts and substations form part of the scope of the proposed work.
The railway line will link to the existing Transnet Freight Rail coal export railway line enabling access
from both directions along the line.
42.
As a railway siding for Eskom’s exclusive use, the capital-costs associated with the proposed
design and construction forms part of the capital investment program to be funded by Eskom. Separate
environmental authorizations have been obtained for the proposed project.6 The purchase of rolling
stock does not form part of the scope. The rolling stock is to be supplied by the proposed operator,
Transnet Freight Rail, and the capital recovery, rolling stock maintenance and management of train
operations is deemed to be part of the transport tariff. Eskom intends to sub-contract the maintenance
of the servitude, the track-work, signaling, control and overhead electrification equipment to a third
party.
Figure 2: South Africa – Existing and Proposed Railway Network
6
Record of Decision (RoD) in terms of Section 22 (3) of the Environment Conservation Act, 1989 (Act 73 of 1989) for the
construction of the Ermelo-Majuba railway line; Environmental Authorization (EA) in terms of regulation 10 (2) of the
Environmental Impact Assessment Regulations, 2006 of the National Environmental Management Act, 1998 (Act 107 of
1998) for the construction of an 88kV distribution line to supply power to the Ermelo-Majuba railway line; Mining permits
for the mining of sand, aggregate and gravel in terms of Section 27 of the Minerals and Petroleum Resources Development
Act, 2002 (No 28 of 2002); and Water Use License in terms of Section 21 of the National Water Act, 1998 (Act 36 of 1998)
for (i) impeding or diverting the flow of water in the watercourse in terms of section 21 (c), and (ii) altering the bed, banks,
course or characteristics of a water course in terms of section 21 (i).
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43.
The cost of operating Majuba Power Plant is in the mid to upper range due to expensive coal
supply. Currently some 6 MT of coal per year are being railed on the General Freight Railway (GFR)
over 340 km by Transnet from the Witbank coalfields to Majuba via Ogies-Springs and the
Johannesburg-Durban main line (Springs-Standerton-Palmfort). Also about 8 MT of coal per year are
being supplied by road trucks via the existing Mpumalanga provincial road network with a weighted
average haul distance (one-way) of approximately 160 km. The importation of coal by these means
was necessitated by the decommissioning of the Majuba Colliery in 1993. The Palmford–Majuba rail
siding was commissioned by Eskom as an interim measure during 1996 to supply three generating
units at Majuba Power Station.
44.
The transportation of coal via the existing provincial road network is deemed to be a nonviable long-term solution. This method of transport is expensive by its nature and has contributed
significantly to the fast deterioration of roads in southwestern Mpumalanga (at present road roughness
indexes of 6 and above are common). A high truck count on these public roads (over 50 percent of
daily traffic) negatively impacts on the road safety and has negative social and environmental
consequences. Truck transport has severe capacity constraints due to the capacity of the existing roads
and the fact that it cannot effectively source and operate sufficient transport units to meet the burnplan.
Figure 3: Location of Collieries for the Majuba Coal-fired Power Plant
45.
Majuba power plant is strategically situated on the grid and it is therefore important to
improve and secure its availability to generate by providing a coal transport system to supply all of its
coal requirements, and to increase its availability potential to a full 90 percent. A long term supply
plan has been developed by Eskom whereby the forecast coal burn at Majuba will require 13 MT per
year.
46.
The potential long-term coal sources that have been identified as being available and suitable
for Majuba Power Station in terms of output tonnages, coal qualities, location and cost are as shown in
Figure 3 and Table 1. Currently no single coal source exists to supply Majuba’s 13 MT per year full
burn requirements. It is important to note that Table 1 lists different coal sources which can now
122
supply coal to Majuba Power Station since these have changed since the original project concept as
coal sources, costs and qualities have changed over time.
Table 1: Proposed Collieries for the Majuba Power Plant
Volume (13Mtpa)
(per month)
Collieries
Distance
General Freight
Kms
Heavy Haul Kms
R 0.28
R 0.15
Rate (2009 - c/ntkm)
Leeupan
50,000
261
111
150
GGV
240,000
205
55
150
0
277
127
150
Koorn
150,000
159
9
150
Uitkyk
50,000
257
107
150
Elders
600,000
146
Hawerklip
146
47.
The original Majuba rail project was approved by the Eskom Board of Directors in 2008, with
the Ermelo Majuba rail line chosen as the best option. The base costs are estimated to be R2.7 billion.
The project has been submitted to the Department of Public Enterprises for approval in line with the
requirements of the Public Finance Management Act.
48.
The following early preparation work has been completed:
a. financial evaluation has been prepared by Eskom Enterprises Division (CED) and
updated in 2009;
b. detailed design of the rail works were completed by the design consultants, Transnet
Projects and a design review conducted by third party rail specialist consultants;
c. land acquisition has been implemented, access to the servitude has been resolved and
all outstanding licenses and permits received including approval of water use licenses
from DWAF and borrow pit licenses from DME;
d. approval to proceed with the rail construction phase has been submitted and agreed to
by the Rail Safety Regulator;
e. an advanced procurement process for the civil works was launched by Eskom in 2007.
The process of calling for tenders from various suppliers for the construction of rail
infrastructure was put on hold pending the completion of purchase of all portions of
the servitude (Eskom eventually cancelled the enquiry as further extending the tender
validity period was not possible without revising the contract rates);
f.
the servitude has been fenced by an appointed fencing contractor. It is a condition of
the RoD that the civil construction can proceed only if the servitude is fenced;
g. Eskom has prepared an environmental impact assessment for the railway line and the
bulk power supply to traction substations and has received an Environmental
Approval for the railway line and a Record of Decision (RoD) to proceed to the design
and construction phase of the 88 kV distribution line to supply power to the railway
line; and
123
h. a revised contracting strategy has been prepared which combines the original three
civil contracts7 into a single package to encourage international participation.
49.
Operational Arrangements: Eskom has also designed with Transnet Freight Rail the tie-in
between the coal export railway line and the proposed railway line. An agreement for the tie in and
alterations to the railway line needs to be concluded between Eskom and Transnet Freight Rail. A
logistics simulation model has been developed to ensure that the 13 MTpa of coal can be handled by
the trains, the tippler and coal stockyard and associated equipment. The results of the model will be
incorporated into broader transport modeling exercises being conducted by TFR to achieve its
medium-term goal of 81 MTpa of export coal.
50.
Eskom will construct and own the railway line infrastructure assets (classified as a siding for
exclusive use by Eskom) and Transnet Freight Rail will be the rolling stock owner and operator. The
commissioning of the line is expected in January 2014. Eskom will sub-contract the maintenance of
the servitude, the track-work and overhead electrification equipment.
51.
A Coal Transportation Agreement (CTA) is under development between Transnet (legal
entity) through TFR (operator) and Eskom Holdings Ltd. The CTA will include the terms and
conditions for the operation of the transportation of coal in the Ermelo-Majuba railway link using
rolling stock supplied, maintained and managed by TFR. A final CTA is expected to be completed no
later than six months after Board approval. Under the CTA, rolling stock is expected to be available to
ensure a minimum supply of coal per month of 1.1 MT to Majuba; such traffic is already part of the
strategic planning considerations of Transnet for its coal logistic operations. The CTA will define the
efforts that TFR is following to secure enough locomotives and jumbo wagons so that such rolling
stock will be available by 2014 considering a 30-month procurement lead-time required.
52.
Eskom will ensure that before the commissioning dates of the coal transport system the
necessary coal supply contracts to meet the coal demand of the power station will be signed. It is
expected that these long-term coal supply contracts will be structured such that the coal will be loaded
via new or existing train loading terminals that tie-in with TFR’s existing export coal rail network.
New rapid-loading terminals and coal yards (such as those found at Elders and GGV), while generally
owned and operated by the mining houses, may also be developed by Eskom. This will depend on their
feasibility as well as future negotiations with coal suppliers. The cost of these terminals is excluded
from the project capital costs as the amortized capital for such is generally included in the ‘free-onrail’ (FOR) purchase price of the coal.
53.
As it is an Eskom-owned line, Eskom will be responsible for the maintenance of the
infrastructure, including the signaling and electrification equipment. This will be done through a standalone contract, either with Transnet or with a third party. If done by a third party, it would need to be
done to Transnet standards before they would operate services over it. Such arrangements are common
in South Africa as well as on other coal railways throughout the world.
54.
Component C.2 — Technical Assistance for Coal-fired Power Plant Efficiency Improvements:
The proposed component will support Eskom’s objectives of achieving a 1 percent reduction in the
average heat rate of its current fleet of coal-fired power stations by 2012. This will correspondingly
reduce the carbon dioxide (CO2) emissions from the power plants. The strategy for these comprises
O&M (0.6 percent) and engineering (0.4 percent) improvements, as explained in Figure 4 below.
Table 2 shows the status and outcome of investigations carried out so far, including the estimated total
capacity enhancements (efficiency improvements).
7
A request for proposals for the main rail contract and electrical substation equipment were issued to the market in March
and July 2008. These tenders were left to expire.
124
Figure 4: Efficiency Improvements in Average Heat Rate of Current Fleet (1%)
1% Heat Rate
Engineered
Improvement
,4% Heat Rate
O&M Improvement
,6% Heat Rate
,2% Heat Rate
Aux Power
,1% Heat Rate
M&RH Steam
Temp
,2% Heat Rate
M/U Water
,1% Heat Rate
Combustion
,1% Heat Rate
AHPack replacem.
,1% Heat Rate
Feed Heaters
,2% Heat Rate
Condensor/ CW
,02% Heat Rate
Billion kWh Proj.
Table 2: Current Status of Investigations on Efficiency Improvements
Power Station
Koeberg
Tutuka
Matimba
Kriel
Gariep
Hendrina
Arnot
Duvha
Matla
Lethabo
Kendal
Van der Kloof
Feasibility Status
ERA approval outstanding
Phase 1 complete
Phase 1 complete
Phase 1 complete
ERA approval outstanding
Phase 1 complete
In Execution
Phase 1 complete
Phase 2 complete
Phase 1 complete
Phase 1 complete
Conceptual Phase
from
to
MW
per
unit
Increase
in
Capacity
( MW)
900
609
665
500
90
200
350
600
600
618
686
120
932
633
710
524
110
234
400
645
640
650
738
140
32
24
45
24
20
34
50
45
40
32
52
20
64
144
270
144
80
340
300
270
240
192
312
40
Capacity Enhancement
Base
Cost
(Rand
Million)
Capacity
Cost
(R/kW)
926.9
1320.20
1660.30
853
327
1386.00
1182.10
887.5
649.6
1517
132
0
14.482
8.463
6.149
5.924
4.087
4.076
3.940
3.287
2.707
790
423
0
55.
Efficiency improvements can be undertaken by either increasing the capacity of transferring
steam to the system or by increasing the efficiency of the system to produce electricity (from turbines,
cooling systems etc.). Table 3 provides an overview of the expected capacity enhancements that are
proposed to be undertaken by distinguishing between steam flow upgrades and energy enhancements.
Table 3: Steam Flow Upgrades and Efficiency Enhancements
Power
Station
Maximum
Continuous
Rating
(MCR; in MW)
Increase in
Capacity
(in MW)
Energy
Efficiency
Enhancement
(in MW)
Steam Flow
Capacity
Enhancement
(in MW)
Energy
Efficiency
Enhancements
(in MW)
Per Unit
Matla
Kendal
Matimba
Lethabo
Hendrina
Duvha
Tutuka
600
686
665
618
200
600
609
40
52
45
29
34
45
26
4
10
20
4
12,5
4
4
125
Steam Flow
Capacity
Enhancements
(in MW)
Per Station
36
42
25
25
21,5
41
22
24
60
120
24
125
24
24
216
222
150
150
215
276
132
Power
Station
Kriel
Maximum
Continuous
Rating
(MCR; in MW)
500
Increase in
Capacity
(in MW)
Energy
Efficiency
Enhancement
(in MW)
Steam Flow
Capacity
Enhancement
(in MW)
24
10
14
Gross Capacity Contribution above MCR
Success Probability
Net Capacity contribution above MCR
Gross Capacity above EL1
Success Probability
Net Capacity contribution above EL1
Total
Energy
Efficiency
Enhancements
(in MW)
Steam Flow
Capacity
Enhancements
(in MW)
60
461
80%
393
79
80%
63
84
1289
50%
645
911
50%
456
519
56.
O&M improvements are ongoing internal efforts in improving practices and procedures, such
as in the reduction in auxiliary power consumption by, for example, reducing redundancies; coal
quality improvement where feasible; and increasing main and reheat temperatures. The proposed
technical assistance component will assist Eskom with the improvements that require external
engineering support (engineered improvements) to improve the net heat rate of the plants.
57.
In the first instance, the proposed component will provide technical assistance to design the
improvements specifically for the three power plants noted below. The proposed component will
finance the cost of international experts to review the work already carried out by Eskom staff, advise
Eskom on the best way forward, and prepare the associated designs, implementation plans and
technical specifications for the recommended sub-projects. In particular, the consultants will, for each
of the sub-projects, assess the feasibility of achieving the estimated heat rate improvements, provide
advice on the proposed designs and on implementation logistics, and prepare the associated
implementation plans. It is expected that the work will serve as models that can be extended to the
remaining power stations.



Hendrina Power Plant to design the replacement of the High Pressure and Low
Pressure turbines (blades, rotors, inner casings);
Matimba Power Station to design the expansion of the cooling system capacity
(extend ACC or construct cooling towers); and
Kendal Power Plant to design the expansion of the cooling system capacity.
58.
The Hendrina Power Station is a ten-unit, condensing-cycle steam-electric generating power
plant with installed capacity (MCR) of 2,000 MW. These 10 units, which were installed and
commissioned between 1970 and 1976, are amongst the oldest in the Eskom fleet of power units.
Average availability over the last 3 years has been about 89 percent. Eskom aims to improve the
overall generating capacity of Hendrina Power Station by improving turbine efficiency. The overall
capacity will increase by 10 x 12.5 MW (125 MW). The 12.5 MW (6.25 percent improvement)
efficiency improvement benefit is envisaged for the current 100 percent steam flow conditions (with
no thermal upgrade). Based on a total capacity increase of 10 X 12.5 MW, the estimated emissions
reduction for the station is 670,833 tCO2e per year if the available capacity is not utilized.
Alternatively if the additional capacity is utilized then this will be available without an increase in
gaseous/particulate emissions. This reduction will be realized over the remaining life of the power
station (2026) with no additional fuel or water requirements.
59.
The Matimba Power Station began construction in 1981. It is located in Lephalale (near the
proposed Medupi Power Plant). Matimba is currently the largest direct dry cooling power station in the
world, an innovation necessitated by the severe shortage of water in the area where it is situated. As a
dry-cooled power station the output and performance is very dependent on the ambient conditions
(specifically wind and temperature). The condenser cooling in any steam power cycle has a major
126
influence on the overall operating efficiency of that process. As the dry-cooled condenser cooling
technology applied in the Matimba process limits the generated efficiency, there is an opportunity to
expand the cooling capacity to overcome this limitation. The root cause of this adverse production
limit resides in the capacity of Matimba’s direct draught air cooled condenser (ACC) which was the
first of its kind to be built by Eskom. The ACC at Matimba has sufficient capacity to allow the station
to produce more than the rated output (665 MW) at low ambient temperatures, but insufficient
capacity to produce at rated output when higher ambient temperatures occur (typically greater than
26ºC). Eskom aims to upgrade the existing air-cooled condenser to overcome the ambient temperature
effects by effectively improving the cycle efficiency under the high ambient temperature condition.
60.
Various options exist to expand the ACC and these include: (a) extending the existing ACC
design by adding two cooling rows (fans and heat exchangers); and (b) constructing separate cooling
towers to supplement the air-cooled condenser performance. Both technology options would lead to
expansion of the existing dry-cooled system capacity at Matimba and a reduction in the increase in
turbine backpressure during high ambient conditions. Both technology options have been used
internationally and the suppliers of the technology are acknowledged specialists in the field of drycooling. South Africa has experience of the direct forced draught air-cooled condenser (Matimba and
Majuba Power Stations) and indirect dry-cooling towers (Kendal Power Station). Eskom has specified
the ACC technology on the Medupi and future power plants, which are under construction and
development, respectively. Improvements in efficiency will yield notable reductions in emission
contributions (especially CO2). The estimated improvement in power station efficiency is equivalent to
an average of 20 MW per unit. Based on the historic performance of the power station this summates
to about 851,472 MWh for the station per year once all units have been upgraded. Applying a
conversion factor of 0.91 tons of CO2 per MWh generated then the saving in CO2 emissions for the
station is about 774,791 tons per year.
61.
The Kendal Power Station is a 6-unit power station, with an MCR of 686 MW per units. The
last unit was commissioned in 1993. The power station design efficiency at rated turbine MCR is 35.3
percent and its average availability is about 93 percent. The engineered plan for Kendal is to enhance
the cooling capacity in order to increase power generation by about 10 MW per unit (60 MW total).
This would results in CO2 emissions saving for the station of about 387,395 tons per year.
62.
Component C.3 — Technical Assistance for development and implementation of domestic and
cross-border renewable energy and energy efficiency projects. The proposed component will support
Eskom to further the development and implementation of domestic and cross-border renewable
projects, including the Upington CSP. Eskom has completed a prefeasibility assessment of the
proposed CSP project. However, there is a need to undertake a comparison of its assessment to
international best practices, which is proposed to be financed by this component. Based on the
recommendation of this assessment, the component will also support Eskom in undertaking the
preparation of a financial review and bidding documents for the Upington CSP. In addition, this
component will also provide technical, financial and legal advisory services to Eskom to develop
domestic or cross-border renewable projects.
63.
The proposed technical assistance would include, but not be limited to, the following
activities:
a. A technical and financial review of preliminary project design;
b. Design and preparation of bidding documents;
c. An assessment of local manufacturing capability for scale up of domestic CSP
manufacturing technology; and
d. An advisory panel consisting of international experts to support Eskom during the
implementation of the project.
127
64.
Technical & Financial Review: Under this activity, consultancy services will be procured to
undertake a review of the current Eskom designs for the proposed Upington CSP project. Solar
technology experts will be appointed; these consultants will conduct an international best practice
study identifying all current and planned CSP projects and will assess these projects and compare them
to the current Eskom design and choice of CSP technology. Completion of this activity will provide
Eskom with a CSP road map including costs, technology, optimal plant capacities, etc.
65.
Design and preparation of bidding documents: This activity will be undertaken upon the
completion of the technical and financial review. Based on the recommendations of the technical and
financial review and agreed design and plant configuration the consultant will assist in preparing the
detailed plant design. The consultants will also support Eskom in preparation of the bidding documents
for the selected design for the Upington CSP.
66.
Assessment of local manufacturing capability for scaling up CSP in South Africa: This activity
will support Eskom in undertaking a local manufacturing capability study to determine the feasibility
of producing components of any CSP plant in South Africa. The appointed consultants will provide an
assessment of which components of a CSP plant can be built for both local and international markets.
For this activity, all CSP technologies will be considered. This assessment will also identify the key
entities (international and domestic) of the CSP value chain and potential new entrants (automotive
industry, glass industry, steel industry, etc.). In addition, the assessment will provide valuable inputs
by undertaking the capacity assessment of technical skills in implementing CSP projects and will
identify critical gaps, if any. To this extent, the consultants will also propose a capacity strengthening
plan to overcome critical capacity gaps.
67.
International Advisory Panel: This activity will support Eskom in setting up an advisory panel
consisting of international experts to offer the necessary advice, guidance, etc. during the
implementation phase of the Upington CSP.
68.
Energy Efficiency: With respect to energy efficiency projects, the technical assistance
provided to Eskom will support a scale-up of demand side management programs through Solar Water
Heaters and assessing the potential for Time of Day metering. The Eskom Solar Water Heating
Program is driven by government which has set a target for renewable energy to contribute 10,000
gigawatt hours (GWh) of final energy consumption by 2013. Solar water heating could contribute up
to 23% of this target. Eskom is supporting this drive through the large-scale introduction of solar
water heating as it is one of the most effective renewable energy sources available. The program has
not been running successfully with only a few hundred transactions since its introduction about 2 years
ago. The proposed technical assistance will assess the reasons for its poor performance and
recommend improvements that would enable the program to be accelerated.
128
Annex 5: Project Costs
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Financing Plan (US$ millions)
Project Component
Costs (US$s)
IBRD
CTF128
Eskom & Other
Lenders
Component A: Medupi Power Project & Associated Transmission Lines
IBRD Financed Future Contracts, incl. Transmission Lines
IBRD Financed Past Contracts
Non-IBRD Financed Contracts
Owners Development Costs
Contingencies
593.03
2,590.89
6,053.68
796.65
762.39
593.03
1,766.37
130.46
0.00
824.52
6,053.68
796.65
631.93
IBRD Loan related Interest During Construction
400.00
400.00
0.00
Construction (AfDB and ECAs only); excluding Eskom's Cost of Balance
Sheet Financing
851.00
150.00
701.00
12,047.64
3,039.86
0.00
9,007.78
55.00
0.00
25.00
50.00
130.00
25.00
25.00
TOTAL - Component A
Component B.1: Sere Wind Power Project
Wind Turbines & Generators, Towers and other Equipment
Civil Works – tower foundations
O&M Building
132 kV Lines and Substations
Owners Development Costs
Contingencies @ 10% of Base Costs
Interest During Construction (IBRD, CTF and identified lenders); excluding
Eskom's Cost of Balance Sheet Financing
210.00
50.00
14.00
50.60
28.40
32.30
TOTAL - Component B.1
30.00
14.00
0.60
28.40
2.30
60.13
0.00
60.13
445.43
110.00
100.00
235.43
250.00
200.00
10.00
150.00
Component B.2: Upington Concentrating Solar Power
Turnkey EPC for CSP
Owners Development Costs
Contingencies @ 25% of Base Costs*
Interest During Construction (IBRD. CTF and indentified lenders); exluding
Eskom's Cost of Balance Sheet Financing
600.00
10.00
150.00
22.68
128
150.00
22.68
The GoSA and Eskom Holdings are currently in advanced stages of discussions with IBRD and AfDB for CTF support to the Sere Wind Power Project and the Upington CSP.
A proposal to the CTF from IBRD and AfDB will be submitted after conclusion of the proposed IBRD Loan.
129
Financing Plan (US$ millions)
Project Component
Costs (US$s)
IBRD
CTF128
Eskom & Other
Lenders
TOTAL - Component B.2
782.68
150.00
350.00
383.31
TOTAL - Component B
1228.11
260.00
350.00
618.74
Component C.1: Majuba Rail Project
Earthworks, Civil Works, Buildings, Perway and OHLE
Traffic Control System (Signaling)
Enabling Works
88 kV substations
Relocation, Access and Noise Mitigation
Consultants - Project Management
Engineering Compliance (Transnet Supervision)
External Civil and Metallurgy Laboratory
Owners Construction and Supervision Costs
Owners Development Costs
Contingencies @ 10% of Base Costs
Interest During Construction (IBRD only); excluding Eskom's Cost of Balance
Sheet Financing
270.00
12.93
4.93
37.00
1.87
11.50
8.50
1.00
26.67
63.58
79.59
270.00
12.55
70.22
26.67
63.58
9.38
28.50
0.00
28.50
TOTAL - Component C.1
546.07
410.77
0.38
4.93
37.00
1.87
11.50
8.50
1.00
0.00
135.31
Component C.2: Technical Assistance for Efficiency Improvements of the Coal Fleet
Assessment, Identification, & Design of Coal-fired Fleet for Efficiency
Improvement Investments
20.00
20.00
TOTAL - Component C.2
20.00
20.00
0.00
0.00
Component C.3: Technical Assistance for Renewable and Energy Efficiency Projects
Technical Assistance for development and implementation of domestic and
cross-border renewable energy and energy efficiency projects.
10.00
10.00
TOTAL - Component C.2
10.00
10.00
0.00
0.00
TOTAL - Component C
576.07
440.77
0.00
135.31
12,499.51
3,200.00
350.00
8,949.51
10.00
9.375
0.625
Interest During Construction
1362.31
550.00
0.00
812.31
Total Financing Required
13,861.82
3,750.00
350.00
9,761.82
Total Baseline cost, inc. Contingencies
Front End Fee (IBRD) and Management Fee (CTF)
130
Annex 6: Implementation Arrangements
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
1.
Eskom, a wholly-owned government entity, will be solely responsible for implementation of
all components of the project and the sole beneficiary of the loan, which will be guaranteed by the
government. Eskom last implemented a program of this size in the 1980s and had lost some of the
skills that it had then. To address this deficit the utility has been recruiting externally specifically for
the project as well as for Eskom operations and maintenance and at present is well staffed to undertake
the proposed investment program.
Institutional and Project Construction/Implementation Arrangements
2.
The proposed projects are high value and technologically challenging projects. The EISP
comprises four large sub-projects, of which one (Medupi Power Project) is already under
implementation with well established implementation arrangements under the Capital Expansion
Department (CED) of the Enterprises Division Business unit. Enterprises, which reports to the
Generation Business unit, will also be responsible for implementation of the other three components,
with the support of other divisions as shown in Figure 1.
Figure 1: Eskom’s Institutional Arrangements
Component A – The Medupi Power Project
3.
Eskom realized at the outset of the new build program which includes coal-fired power plants
among others that a shortage of skills and knowledge existed both within Eskom and South Africa. To
address this shortage Eskom appointed a few experienced engineering houses as execution partners
with the necessary skills. For Medupi, the execution partner is Parsons Brinckerhoff (PB). PB leads the
the execution team which comprises a mix of Eskom and PB staff, and their mandate includes the
transfer of skills to the local workforce.
131
4.
Project oversight: The oversight of the project is governed by a Medupi Leadership Committee
which consists of eight senior management representatives (Chief Operating Officer / Senior General
Manager / General Manager) from Eskom and PB. The PB representatives include the Chief Operating
Officer (COO) of PB Africa and COO of their US arm. This committee is required to hold at least six
regular meetings per annum but it currently meets on a monthly basis to discuss strategic matters and
the unlocking of complex project issues. Strategic quarterly meetings are also held with representatives
of all functions to provide project feedback to management as well as the Generation Division as the
ultimate owner of the station. The committee has the authority to create and delegate specific tasks to
the Medupi Project Team (MPT) and to other Eskom Divisions as it may determine appropriate for the
discharge of its responsibilities. The results of the meetings are reported to the full Boards of Eskom
and PB.
5.
The Medupi Project Team and Medupi Execution Team: The overall Medupi project which
includes addressing the transmission interfacing, licensing, public liaison, industrial relations and other
traditional functions is the responsibility of the MPT under the management of the Medupi Executive
Project Manager. The project teams are further supported by various divisions in Eskom; in particular,
Finance, Treasury and Corporate Services as shown in Figure 1 above. In total, there are 38 Medupi
Execution Teams (MET) for specific contracts to review vendor design, system integration and project
execution. The project’s implementation organogram is provided in Figure 2.
6.
The Medupi Execution Team (MET) is a subset of the Medupi Project team and is composed
of members provided by Eskom and PB. Upon completion of the project the team will be disbanded
and its members demobilized and re-absorbed in the home divisions and/or organizations.
Figure 2: Medupi Power Project – Implementation Teams
7.
The Project structure clearly distinguishes between the roles of the MET and MPT. CED
fulfils its responsibilities through the role of the Medupi Project Manager. PB fulfils its obligation
through the Medupi Project Execution Manager who in turn reports to the Medupi Project Manager.
8.
Construction of the power plant: Most of the contracts for Medupi Power Plant have already
been awarded (see Annex 8 for details related to the project’s procurement arrangements). The two
largest contracts for boilers and turbo-generators/tubines have been awarded. The turbine contractor
has been tasked to take primary responsibility for interfacing with the other contractors. Both
132
contractors have wide international experience in similar projects, including execution of previous
contracts with Eskom. See Annex 4 for additional details on construction related information.
9.
Coal supply: Coal will be supplied from an existing independent coal mine (Grootegeluk),
owned by Exxaro and transported to the power plant via a conveyor system. The mine currently
supplies coal to the nearby Matimba Power Stations. A Coal Supply and Offtake Agreement has been
entered into by Eskom for the supply of coal to the Medupi Power Plant. See Annex 4 for additional
details on Coal Supply related information.
10.
Water supply: Responsibility for the timely supply of water for Medupi rests with the
Department of Water Affairs (DWAF).
11.
The six units of Medupi will require about 6 million cubic meters per year to operate. In
addition, the FGD proposed to be installed later by Eskom will require at least another 6 million cubic
meters per year. The source for the initial 6 million cubic meters will be from the Mokolo River and
dam. There is currently enough water in the Mokolo River, and Eskom has permits, to operate the first
three Medupi units. To permit the next three units, and to ensure the environmental base flow,
augmentation of the current Mokolo River pipelines and related infrastructure is required (Phase 1). To
reach 12 million cubic meters per year required for FGD, a basin transfer system would have to be
built, bringing water from the Crocodile River Basin (Phase 2, 3 and 4) - the Crocodile Water
Augumentation Scheme which is being developed to meet the water requirements of Lephalale
municipality. This augumentation scheme will therefore be developed irrespective of the Medupi
Project.
12.
Improvements to the existing Mokolo River system (Phase 1) include: (i) a weir and a short
pipeline to overcome a gradient and pipe bottleneck that will increase flow through by 20 percent; and
(ii) laying a new pipeline parallel to the existing pipeline from the Mokolo dam to the Medupi site.
Phase 1 will add 6 million cubic meters per year to the existing capacity and will cost an estimated
R1.9 Billion. The financing of Phase 1 has two options. Option 1 is for off-taker agreements to be
signed with DWAF by the three major water users: Eskom, Exxaro and the Town of Lephalale and
other users. An existing special purpose vehicle is expected to carry out the construction after
obtaining private sector funds backed by the off-taker agreements. Option 2 is for the Development
Bank of South Africa to finance the construction. In addition, the National Treasury has budgeted
R900 million over five years for augmenting water supply for Lephalale. Construction time is
expected about 2.5 years in time for the operation of the last three units of Medupi Power Plant.
13.
The basin transfer scheme from the Crocodile River (Phase 2 - 4) includes the construction of
a 100 km pipeline to carry 100 million cubic meters per year to Lephalale, at an estimated cost of R7.3
billion. Construction is expected to be completed of Phase 2 as early as mid-2015.
14.
The risk of ensuring sufficient water for operating the six units (without FGD) is low. The risk
of not having sufficient water to operate the FGD plant post 2015 is moderated by the GoSA
undertaking in the Guarantee Agreement to supply the required amount of water (including FGD) for
the Medupi Power Plant.
15.
Operations of the Power plant: Upon commissioning, the power plant will be handed to
Generation operations (also under Generation Business). Eskom has already identified staff that will
be responsible for operation and maintenance of the power plant. In preparation for operations,
arrangements have been made to provide training to the O&M staff. Consistent with best international
practices, the training includes on-the-job-training by the construction contractors as well as hands-on
training at similar facilities outside the country.
133
Component B.1 – The Sere Wind Power Project
16.
The proposed project has been developed by the Capital Expansion Department (CED) within
Eskom Enterprises. The CED will be responsible for the complete procurement phase. Upon
completion of the procurement phase (signing of a specific construction/supply & install contract), the
contract will be handed over to a project manager under CED for construction supervision and
management. Operation of the power plant will be undertaken under a proposed new “Wind”
department in Generation Business responsible for peaking plant.
17.
The GoSA has also constituted an inter-departmental Committee (DoE, DoEA, DPE and
Eskom) for Strategic Guidance to provide oversight with respect to CTF-funded components, namely
B.1. and B.2.
Component B.2 – The Upington CSP Project
18.
This sub-component will be implemented in two phases. The first phase will involve review of
preparatory work already carried out by Eskom, including the project concept and preliminary design.
This phase will be managed by Corporate Services. The second phase will involve procurement and
construction supervision and management (under CED).
19.
In the second phase, the CED will be responsible for the complete procurement phase. Upon
completion of the procurement phase (signing of a specific construction/supply & install contract), the
contract will be handed over to a project manager under CED for construction supervision and
management. Operation of the power plant will be undertaken under a proposed new “Solar”
department in Generation Business responsible for the peaking plant. Eskom has indicated that since
Upington CSP is a pilot project to develop the long-term CSP potential in South Africa, Corporate
Services will continue to be involved throughout the project’s implementation as well as during
operations to monitor and evaluate performance.
Component C.1 Majuba Rail Project
20.
The proposed Majuba Rail project has been well-studied for a number of years and the
technical design of this component is complete. Every contract that needs to be procured will be led by
a dedicated buyer (manager for overseeing individual procurements). Eskom has already established a
project management unit for this component, headed by a project manager, under CED, for
construction supervision and management. Transnet Freight Rail (a public entity that owns and
operates most of rail transport network in South Africa; TFR) will provide the Eskom team expert
advice as and when required. TFR will also be responsible for engineering compliance.
21.
Eskom will construct and own the railway line infrastructure assets (classified as a siding of
exclusive use by Eskom), while TFR will be the rolling stock owner and operator. A Coal
Transportation Agreement (CTA) will be signed between TFR (the proposed operator) and Eskom.
Eskom will sub-contract the maintenance of the servitude, the track work and overhead electrification
equipment. Within Eskom, the operation of the project will be the responsibility of the Primary Energy
department, also reporting to Generation Business.
Component C.2 Technical Assistance for Energy Efficiency Improvements
22.
The proposed technical assistance component will be managed by a project manager within
Generation Business. Eskom will follow the Bank’s Consultant Guidelines and will use the Bank’s
Standard Request for Proposals for Consultant Contracts for Bank financed procurements.
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Component C.3 Technical Assistance for Development and Implementation of Domestic and Crossborder Renewable Energy and Energy Efficiency Projects
23.
The proposed technical assistance component will be managed by a project manager within
the Corporate Services division of Eskom. Eskom will follow the Bank’s Consultant Guidelines and
will use the Bank’s Standard Request for Proposals for Consultant Contracts for Bank financed
procurements.
Safeguards Monitoring and Management
24.
The safeguards unit within Generation Business (assisted by safeguards staff from the
Corporate Division) will be responsible for all aspects of environmental and social safeguards for all
components of the project, including communication and consultation with stakeholders and project
affected people.
25.
Eskom has already established a Health, Safety, Environment and Quality (HSEQ) system for
the Medupi project, which meets international standards, under the HSEQ Manager. The system will
be replicated for the other investment project components. Other responsible officers/ entities/
stakeholders for the Medupi project include:







Environmental Control Officer – ensuring compliance with the ROD and EMP, and reporting
directly to the Department of Environmental Affairs
The MET
Eskom Generation Environmental Management
Eskom Corporate Services (legal, compliance, assurance)
Environmental Monitoring Committee
Government and Municipal Departments (DEWA, DoE, etc)
Lephalale Fire Management
26.
Eskom has also developed a workplace AIDS program, which it extends to family and
community members and to Eskom suppliers, including project sites. A review of the program by the
USAID-supported Horizon’s Program in 2005 highlighted the following:




Eskom’s program successfully addressed gaps in HIV/AIDS knowledge among workers and
catalyzed the dissemination of information by workers to family and community members.
Eskom’s training activities increased the capacity of peer educators and supervisors to
confront the stigma in the workplace and community, but more work is needed to address
workers’ lingering concerns about stigma and confidentiality.
Eskom’s investment in the training of family members of employees and community-based
NGOs created an important link between the workplace and community HIV/ AIDS services,
but better coordination and role clarification is needed.
Workplace HIV/ AIDS programs need continued attention, and operations research provides
direction to address program challenges.
Monitoring and Evaluation of Outcomes
27.
The Project Coordinator (From the Finance Directorate) will be responsible for coordination
and monitoring of progress of the overall project. The Project Coordinator will facilitate coordination
between the five project managers and between Eskom, the shareholder (DPE), DoE and NT.
28.
The key indicators to be monitored and used in assessing the project progress and evaluation
of outcomes are described in Annex 3—Results Framework and Monitoring. Specific data for
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gathering and reporting, including responsibilities thereof, have been agreed with Eskom. A mid-term
review would be carried out within approximately 30 months (2.5 years) from effectiveness of the
IBRD Loan.
IBRD Implementation Support
29.
An IBRD implementation support strategy has been designed (see Table 1) to suitably match
the requirements and complex issues to be addressed under the project. The focus will be on
anticipating and managing risks that could impact the project as noted in Section III.E of the Main
Text. Consequently, the IBRD team will be staffed with the requisite expertise. At least one
implementation support mission will be undertaken before the end of FY2010, soon after the loans
become effective, and two missions will be undertaken in FY2011. Missions will include safeguards
and fiduciary staff. Implementation Support will be coordinated with other financiers such as AfDB
(and other potential lenders) where possible and maximum utilization will be made of field-based staff.
In addition, depending upon the activities being undertaken in the project, intensive concentration at
certain times during construction and more focused attention at some locations would be undertaken.
Table 1: IBRD Implementation Support
Planned
Date
Skills Requirement
Main Activities
5/2010
Project Launch Workshop:
Review implementation plan, FMS, Disbursements,
procurement and reporting
TTLs, Procurement Specialist, Safeguards Specialists,
Financial Analyst, Water Specialist, Communications
Specialist, M&E Specialist, Financial Management
Specialist
9/2010
Review overall progress, focusing on prospective
procurement, safeguards, water supply for Medupi,
Medupi progress, FMS, macro, financial and sector
risk reviews, and progress on CSP, Wind, Majuba Rail,
TA Phase 2
TTLs, Power Engineers, Procurement Specialist, CSP
& Wind Specialist, Macro Economist, Rail Specialist,
HIV/ AIDS Specialist, Regulatory Specialist, Financial
Management Specialist
1/2011
Review overall progress, prospective procurement and
safeguards
TTLs, Financial Analyst, Procurement Specialist,
Safeguards Specialists
7/2011
12/2011
4/2012
Review overall progress, water supply for Medupi,
CSP, Wind, Majuba Rail and Eskom financial
performance
Review overall progress, focusing on prospective
procurement, safeguards, water supply for Medupi,
Medupi progress, macro and financial risk reviews,
and progress on CSP, Wind and Majuba Rail, FMS
Review overall progress, water supply for Medupi,
CSP, Wind and Majuba Rail
TTLs, Power Engineers, Procurement Specialist, CSP
& Wind Specialist, Water Specialist, Financial Analyst
TTLs, Procurement Specialist, Financial Analyst,
Power Engineers, Rail Specialist, Macro Economist,
Financial Management Specialist
TTLs, Power Engineers, Procurement Specialist, CSP
& Wind Specialist, Water Specialist
9/2012
Review overall progress, CSP, Wind and Majuba Rail
TTLs, Procurement Specialist, Financial Analyst,
Power Engineer, Rail Specialist
1/2013
Mid-Term Review:
Review MTR report, overall progress, M&E, Eskom
financial performance, macro, financial and electricity
sector risks review, FMS
TTLs, Power Engineers, Procurement Specialist, CSP
& Wind Specialist, Water Specialist, Macro
Economist, Rail Specialist, M&E Specialist, HIV/
AIDS Specialist, Regulatory Specialist, Financial
Management Specialist
9/2013
Review overall progress, CSP, Wind, Majuba Rail,
Eskom financial performance, safeguards, FMS
TTLs, Procurement Specialist, Financial Analyst,
Power Engineer, Rail Specialist, Safeguards
Specialists, Financial Management Specialist
136
Planned
Date
Skills Requirement
Main Activities
2/2014
Review overall progress, CSP, Wind and Majuba Rail
TTLs, Procurement Specialist, Power Engineer, Rail
Specialist
10/2014
Review overall progress, CSP, Wind, Majuba Rail,
Eskom financial performance, safeguards, FMS
TTLs, Procurement Specialist, Financial Analyst,
Power Engineer, Rail Specialist, Financial Analyst,
Safeguards Specialists, Financial Management
Specialist
3/2015
Review overall progress, CSP, Wind and Majuba Rail
TTLs, Procurement Specialist, Power Engineer, Rail
Specialist
11/2015
Implementation Completion Report:
Review overall progress, including M&E, FMS, and
Eskom financial performance, and prepare for ICR
report.
TTLs, Power Engineers, CSP & Wind Specialists,
Safeguards Specialists, Financial Analyst, Energy
Economist, Rail Specialist, Financial Management
Specialist
30.
From the Safeguards perspective, implementation support will be provided at two levels. On
the first level, the Bank will help support the monitoring the performance of project implementation
using country systems. Bank support will involve evaluating the quality of additional safeguards
documents that may be produced, with respect to GoSA requirements and OP 4.00, and reviewing
various independent audit reports that Eskom will produce, on resettlement/land acquisition, health
and safety, and EMP implementation. On the second level, the Bank team will review results on the
ground. Safeguards specialists will join supervision missions and will schedule site visits during those
missions so that each generating facility with its transmission line and the Ermelo-Majuba Rail Line
are visited no less than once a year. Facilities at which there are significant social, environmental or
health and safety concerns will be visited twice annually in the first two years of their implementation.
31.
The contracts for the Medupi Power Plant, which have already been procured, will require
technical and implementation supervision which would be ensured through continuous supervision and
interactions with Eskom. As recommended in the capacity assessment of Eskom, post review of
procurement contracts will be carried out once a year.
32.
Based on the above Implementation Support plan, the Bank’s estimated implementation
supports budget (see Table 2) from FY10 to FY16 is estimated below for a Total Cumulative spending
of about US$ 3 million:
Table 2: IBRD Implementation Support
IBRD Fiscal Year
FY10
FY11
FY12
FY13
FY14
FY15
FY16
Amount of Resources
Required (US$,000s)
200
400
400
450
450
500
500
33.
The following measures are proposed to ensure more effective implementation and monitoring
of outputs and results.
(i)
Continuous engagement through country based staff.
(ii)
Building on the experience and learning from other large value, complex infrastructure
projects such as the Nam Theun II and Bujagali Power Project in terms of risk
assessment and mitigations, anticipation and proactive attention to risk issues,
particularly on safeguards. Consistent with learning from such projects, focus on
developing strong relationships with Eskom implementation teams, mutual learning
and capacity building initiatives/events and joint supervision of project activities,
including interactions with stakeholders.
137
(iii)
(v)
Staff exchange between the Bank and Eskom to develop mutual understandings,
enable knowledge transfer and strengthen capacity.
Maintain proactive communications and consultations with project stakeholders and
civil society.
Enhance opportunities for regional energy transactions.
(vi)
Strengthen donor/partner alliances to share information and implementation support.
(iv)
138
Annex 7: Financial Management and Disbursement Arrangements
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
1.
The proposed project will consist of 3 components which are presented in Section II.C of
PAD.
2.
The Bank conducted an assessment of the financial management arrangements for the
proposed Project as required by the Bank’s policy on Financial Management, OP 10.02, and in
accordance with the provisions of the Financial Management Manual, dated March 1, 2010. Eskom is
the implementing agency for the proposed project. The main objective of the assessment, which
included a review of the budgeting, accounting, internal controls, flow of funds, financial reporting,
auditing arrangements at Eskom, and completion of FM assessment questionnaire by some officials of
the agency, was to ensure that acceptable financial management arrangements are in place for the
implementation of the project.
3.
Acceptable FM arrangements require that:



funds are used for the intended purposes in an efficient and economical way,
all transactions and balances are correctly recorded to support preparation of regular and
reliable financial statements that are subject to auditing arrangements acceptable to the Bank,
and
internal controls are considered capable of safeguarding the entity’s assets.
4.
Eskom’s audited financial statements are acceptable to the Bank without a requirement for a
separate audit report for the project.
5.
The governance and accountability arrangements in place at Eskom, coupled with the
oversight responsibilities provided by DPE, and the interest of the stakeholders and the public at large
in the effective management of the Company are acceptable for ensuring efficient and effective
utilization of the project funds and reporting of the activities of Eskom. In addition, the internal and
external auditors have unrestricted access to the Chairman of the Audit Committee as a measure to
ensure efficient and effective corporate governance.
6.
The FM assessment identified the financial management risks that Eskom may face in the
implementation of the project, and proposed measures to mitigate the risks, as shown in the risk
assessment matrix (see Table 1 below). Eskom’s system is capable of managing the project
expenditure efficiently and effectively: accounting for utilization of the loan proceeds; ensuring
effective internal controls; producing quarterly Interim Financial Reports for the project; and ensuring
timely audit of the annual financial statements. The overall FM risk is Low based on the proposed use
of Eskom’s FM system, and the oversight arrangements imposed by government on its parastatals as
well as the implementation of the FM actions as noted below. The overall conclusion of the assessment
is that the proposed FM arrangements meet the Bank’s minimum requirements under OP 10.02
Financial Management.
Country issues
7.
The South African public expenditure management system has undergone substantial reform
since the mid-1990s. While the early reforms have shaped macroeconomic stability and strengthened
public spending, the more recent emphasis of the reform program has been on efficient resource
allocation and effective service delivery. The highlights of the reform program have been the roll out
of a new intergovernmental system that requires all the three levels of government to formulate and
approve their own budgets; the introduction of 3-year rolling spending plans for all national and
provincial departments under the Medium Term Expenditure Framework (MTEF); new formats for
budget documentation that include a strong focus on service delivery information; the enactment of
139
new financial legislation; and substantial improvements in financial reporting and auditing
arrangements.
8.
A Public Expenditure Financial Accountability (PEFA) Framework Assessment was
conducted between June and September 2008. The assessment found that South Africa scored well in
the following six critical dimension areas of Public finance Management (scored A in the first three,
B+ in second two and B on the last one):
i. Credibility of the budget,
ii. Comprehensiveness and transparency,
iii. Predictability and control in budget execution,
iv. Accounting, recording and reporting;
v. External scrutiny and audit, and
vi. Policy based budget.
9.
The assessment, based on the PEFA Performance Report indicates that the fiduciary aspects
are satisfactory.
Project Implementation Arrangements
10.
Annex 6 provides a complete overview of the project implementation arrangements. All of the
project components will be implemented by Eskom, under the Enterprises Division in the Generation
Business Unit. Overall coordination and interaction with the IBRD will be through a project
coordinator in the Finance Directorate. All project components will have a project manager, under who
there will be a team consisting of engineering, financial, safeguards and commercial expertise.
Institutional support in these areas will also be provided from the respective departments.
11.
Oversight of the project will be provided by an ad-hoc committee comprising Eskom senior
management, at the levels of Chief Operating Officer, Senior General Manager and General Manager.
12.
For the FM implementation of the project, Eskom will use its existing SAP-based FM system
with appropriate oversight by DPE and the Board.
13.
Table 1 provides an overview of the identified FM risks and the proposed mitigating measures.
Table 1: FM Risk Assessment and Risk Mitigation Measures
Risk
Risk Rating: H (High), S
(Substantial), M (Moderate), L
(Low), NA (Non Applicable)
Country Level
Rating
Risk Mitigation Measures
Residual
Risk
Negotiation/
effectiveness
condition
(Y/N)
L
 Key FM oversight elements of the project are
entrusted to the Government’s External Audit
function being the Office of the auditor general. The
position and office of the Auditor General meet all
the standards of independence set by International
Organization of Supreme Audit Institutions
(INTOSAI).
 The Bank will conduct comprehensive training
on the Bank’s FM and Disbursement policies and
procedures by effectiveness of the loan agreement.
Staff of the Eskom Enterprise and the Internal Audit
units will be encouraged to participate in the Bank’s
periodic training program in FM and disbursement,
and in courses organized by Bank recognized
training institutions.
 Eskom has the capacity to handle the size and
scale of this project. The entity’s reputation through
its audited financial statements reflects good
governance and oversight structure.
L
N
L
N
Accountability and usage of the
project’s funds.
Entity Level
Eskom is not familiar with and
therefore has limited knowledge of the
Bank’s FM and Disbursement policies
and procedures.
M
140
Risk
Risk Rating: H (High), S
(Substantial), M (Moderate), L
(Low), NA (Non Applicable)
Project Level
Rating
Risk Mitigation Measures
Residual
Risk
Negotiation/
effectiveness
condition
(Y/N)
M
 Eskom is engaging the shareholder and is
actively raising funds in the debt market on the
strength of the government support through
guarantees of R176 billion for the successful
implementation of the project.
 The government has made R60 billion
subordinated loan payable over three years available
for the build program.
 Eskom has secured the loan from AfDB to fund
the project.
L
N
M
 When the capital expenditure program is under
taken the projects are subjected to robust due
diligence reviews before approval by the board.
 Eskom follows a robust monthly management
reporting process to monitor deviations on plans.
 Eskom has documented policies for approvals
of deviations from plans.
 In addition Eskom is regulated by PFMA
(through materiality significance framework) to seek
shareholder approval for variations in excess of R5
million.
L
N
Non-Availability of other funds to
finance the build program may impact
on successful implementation of the
project.
Control Risk
Budgeting: due to the nature of the
project and escalations in the power
construction industry, there is a risk
that budget process may not be based
on realistic cost estimates.
Procedures for approvals and
variations may not be clearly laid out.
Accounting
NA
NA
NA
No identified risk.
Eskom prepares monthly financial
statements that are presented through
the governance committees. Eskom
uses SAP accounting software, which
is capable of producing the required
financial reports. The Eskom
Enterprise unit is staffed with
professionally qualified accountants.
Internal Control
NA
NA
NA
L
N
N/A
N/A
No identified risk.
Eskom has an effective Internal Audit
Unit. The Internal Audit General
Manager has unrestricted access to the
Chairman of the Audit Committee.
The Audit Committee oversees
Eskom’s internal control systems and
their effectiveness.
Funds Flow
L
There is a risk that funds may be co
mingled with other funds complicating
accountability for the Loan proceeds.
Financial Reporting
 Eskom will maintain a separate bank account
for the funds received from the IBRD Loan for the
implementation of the Bank financed components of
the project. The project will be configured in SAP to
track expenditure by sources of funding.
N/A
No identified risk.
Eskom produces quarterly financial
reports for submission to DPE. The
submission is regulated by the PFMA
and Eskom has complied with the
submission dates. Eskom will also be
able to produce quarterly IFRs for the
project from their SAP accounting
system.
141
Risk
Risk Rating: H (High), S
(Substantial), M (Moderate), L
(Low), NA (Non Applicable)
Auditing
Rating
Risk Mitigation Measures
Residual
Risk
Negotiation/
effectiveness
condition
(Y/N)
NA
NA
NA
M
L
No specific audit risk.
As a schedule 2 entity the PFMA
requires Eskom to produce annual
audited financial statements within
five months after financial year end.
Overall FM Risk Rating
Eskom as the Implementing Agency
14.
Eskom Holdings Limited (“Eskom” or the “Company”) is South Africa’s national, vertically
integrated electricity utility and is wholly owned by the South African government (GoSA). Details on
Eskom financial and operational performance are provided in Annex 1 and Annex 10.
15.
Eskom operates its business through its divisions (Generations, Corporate and Customer
networks) and its subsidiary companies (Eskom Enterprises, Escap, Eskom Finance). Eskom is
managed by its Board of Directors. The Board of Directors is vested with the power and authority to
lead, control, manage and conduct the business of Eskom Holdings Limited. The Board has power and
authority to delegate the responsibility to ensure that the Company remains a sustainable and viable
business of global stature. The Board consists of individuals with wide ranging experience from the
Utilities sector to Social Welfare & Development providing Eskom with depth of skills and expertise.
16.
The Board Committees include the following:
(i)
Audit Committee, which comprises five independent non-executive directors. The
committee ensures that internal audit function is in place and that the roles and functions of the
external audit and the internal audit are sufficiently clarified and coordinated to provide an
objective overview of the operational effectiveness of the Company’s systems of internal
control, risk management, governance and reporting. The committee also reviews the
accuracy, reliability and credibility of statutory financial reporting. In the 2009 financial year
ten committee meetings were held.
(ii)
HR, Remuneration and Ethic which comprise three independent non executive
directors and an external member. The committee makes recommendations on remuneration
and other human resource related policies.
(iii)
Investment and Finance which comprises four independent non executive directors.
The committee reviews the investment strategy and makes recommendations to the Board. It
evaluates and approves business cases for new ventures or projects, approves criteria and
guidelines for investments and approves investments within delegated authority. In the 2009
financial year eight committee meetings were held.
(iv)
Tender which assists the Board with procurement decisions, tenders and contracts
within its delegated authority and approves procurement policies. It ensures that Eskom’s
procurement system is equitable, transparent, competitive and cost effective. This is a five
member committee and has held twelve meetings in the 2009 financial year.
(v)
Risk Management, which ensures that the Company’s risk management strategies and
processes are aligned with best practices. The chairman of the audit committee is a member of
this committee for synergy between the committee and audit committee. The committee has
four independent non executive members and has held four meetings in the 2009 financial
year.
142
(vi)
Sustainability, which comprises four independent non executive directors and an
external committee member. This committee deals with integrated sustainability issues and
makes recommendations on policies, strategies and guidelines, particularly related to safety,
health, environment, quality and nuclear issues.
(vii)
Executive Management that assists the Chief Executive in guiding the overall
direction of the business and exercising executive control. Its task is to assist with the effective
management of the day to day operations of the business. Twenty meetings were held in 2009.
(viii) Ad-hoc committee/coordination committee. The Project Coordinator from Eskom
Treasury will be responsible for coordination and monitoring of progress of the overall project.
The Project Coordinator will also facilitate coordination between the five project managers
and between Eskom, the shareholder (DPE), DoE and NT.
17.
The key indicators are to be monitored and used in assessing the project progress and
evaluation of outcomes. Specific data for gathering and reporting, including responsibilities thereof,
have been agreed with Eskom. A mid-term review would be carried out within approximately 30
months from effectiveness of the loan.
18.
The project FM assessment is strengthened by the adequate external audit arrangements and
the noted timely production of the financial statements and audit thereof within a period of five
months. External auditors’ observations and recommendations are followed-up promptly by the Audit
Committee.
19.
However, Eskom has not been involved in the implementation of Bank financed projects for
over two decades and thus does not understand the Bank procedures well. To this extent, the Bank’s
FM specialists will deliver workshops on the Bank’s financial management and disbursement, policies
and procedures, including reporting requirements during project launch and on a continuing basis.
Eskom’s Corporate Finance unit staff will also be encouraged to attend training programs offered by
Bank accredited training institutions.
20.
Table 2 provides the list of key FM actions that need to be taken by Eskom for the project.
Table 2: FM Action Plan
Action
1. Conduct training of Eskom
accounting staff in Bank
disbursement procedures
Effective date
After Effectiveness
Responsibility
Eskom and Bank FM Specialist
and LOA Finance Officer
21.
Budgeting. Details regarding the financing plan for the project and financing provided by the
GoSA to Eskom are provided in Annex 5 and Annex 9. Eskom’s Corporate division management
accounting and systems department is responsible for the coordination of the Eskom Holdings’ overall
budget. Budgeting process starts in September each year with a budget circular from the office of the
CEO. Each business unit prepares strategic agenda—a five year business plan with mandates and
achievements, risks, and steps to be taken to achieve the budget. The final draft budget is approved by
the management executive committee and the revised budget submitted by the CEO to the Board for
approval, through the Executive management committee (Exco). The budget is then submitted through
the Annual Corporate Plans to the Department of Public Enterprise for Approval and submission to the
National Treasury. The Annual Corporate Plans are submitted by the 28 February of each year for the
coming fiscal year and this process is regulated by the Public Financial Management Act (PFMA).
22.
Accounting. Eskom Holdings finance group is headed by the Chief Financial Officer, a
professionally qualified chartered accountant, and consists of two divisions (Generations and
Corporate divisions) and three subsidiaries (Eskom Enterprises, Escap Limited and Eskom Finance
Company (Pty) Ltd).These divisions and subsidiaries are headed by highly qualified senior managers,
143
most are professionally qualified chartered accountants. Eskom uses the SAP accounting software and
the financial statements are prepared in accordance with the International Financial Reporting
Standards (IFRS).
23.
Eskom Enterprises division is responsible for budgeting of the entire capital expenditure
program. This division is headed by the General Manager who is supported by senior managers and
qualified chartered accountants. The Enterprises Division plays an important role in the New Build
Program, and also offers strategic and commercial life-cycle services to Eskom’s line divisions.
24.
Staffing. Eskom Corporate Finance has a staff compliment in excess of 2000 staff.
25.
Internal control. Management is charged with the responsibility of establishing an effective
internal control environment, including adequate internal financial controls. In addition, operational
control systems are developed and maintained on an on ongoing basis to provide reasonableness
assurance to the board regarding the integrity and reliability of the financial statements; the
safeguarding of its assets; the economic and efficient use of resources; the verification of the
accomplishment of established goals and objectives; the detection and minimization of fraud, potential
liability, loss and material misstatement; and compliance with applicable legislation and regulations.
These controls are contained in organizational policies and procedures, structures and approval
frameworks, and they provide direction, establish accountability and ensure adequate segregation of
duties and each contain self-monitoring mechanisms. The Board ensures that an effective internal
control framework has been established. The Assurance and Forensic department assumes the internal
audit function, monitors the operation of the internal control systems and report findings and
recommends improvement to management and the Audit Committee. The Audit Committee monitors
and evaluates the duties and responsibilities of the management and of internal and external audit to
ensure that all major issues reported have been satisfactorily resolved.
26.
Internal audit. During the period under assessment, the corporate departments of audit,
technical audit, technical investigations as well as forensic and anti-corruption were integrated into the
Assurance and Forensic Department (AF). In line with the requirements of the PFMA and good
governance, the AF provides the Audit Committee and management with independent, objective
assurance, consulting and forensic services designed to add value to improve Eskom’s operations. The
department brings a systematic, disciplined approach to the evaluation and improvements of the
effectiveness of risk management, control and governance processes. The AF is governed by
international standards and best practices, published by recognized professional institutes.
27.
A risk based audit approach is followed by AF. The audit plan is based on the risk assessment
and other considerations, such as the achievement of the organizational business objectives. The audit
plan is updated as required (minimum quarterly) to reflect significant changes in the risk profile
resulting from changes in the business operations, changes in customer needs or regulatory
requirements. AF is supported by the Board and the Audit Committee and is authorized to have
unrestricted access to all functions, records, property and personnel. The AF is headed by the General
Manager, a qualified chartered accountant. The General Manger is supported by seven highly qualified
senior managers (some are chartered accountants, holders of master degrees). The department has 144
established positions.
28.
Eskom Enterprises division has its own Audit Committee which meets quarterly to review
amongst other things internal audit reports. The project will be covered in the annual audit plan of this
division.
29.
In February 2009, KPMG was engaged to perform Quality Assurance on Eskom Internal
Audit Department. The review indicated that overall, Eskom’s internal audit meets the “General
Conform” Section IIA of international auditing standards.
144
30.
Financial reporting. Eskom’s accounting system is capable of producing the quarterly reports.
Eskom produces monthly financial statements that provide information on the entity’s performance
highlights. The monthly reports feed into quarterly reports that are submitted to the DPE 31 days after
the end of the quarter. The format and contents of the unaudited quarterly financial reports have been
discussed with Eskom and will be agreed at negotiation.
31.
Eskom will produce and submit interim unaudited financial reports (IFRs) to the Bank on a
quarterly basis. These reports are designed to provide sufficiently detailed and timely information to
the project management, and the coordination committee, and will include:
(i)
(ii)
(iii)
(iv)
(v)
(vi)
A narrative summary of the project implementation highlights;
Sources and Uses of Funds by disbursement categories;
Uses of Funds by project component/activity- both actual and cumulative;
The Designated Account activity statement;
Summary of payments made for contracts subject to the Bank’s prior review; and
Expenditure Report specific to the IBRD loan.
32.
The quarterly Sources and Uses of Funds report will reflect contributions from all the
financiers and utilization of the funds, while the reports listed in (iv) to (vi) will reflect Bank-eligible
expenditures only.
Funds Flow and Disbursement Arrangements
33.
Flow of funds. Upon the signing of the Loan Agreement, the Bank will open an IBRD Loan
Account in its books, in the name of Eskom. Funds will flow from the Bank (Loan Accounts) into
Designated Account (DA), maintained by Eskom for each currency in which the loan is disbursed.
34.
Disbursement arrangements. Eskom will maintain a US$ denominated segregated Designated
Account (DA) in a commercial bank for the implementation of Bank-financed components of the
project. Disbursements by the Bank into this account will be based on the quarterly Interim Unaudited
Financial Report (IFR) and withdrawal applications prepared and submitted by Eskom to the Bank.
The submission will be required within 45 days of the end of each reporting period. Upon
effectiveness of the loan agreement and submission of a withdrawal application, the Bank will initially
disburse an amount equivalent to six months estimated project expenditures into the DA. Subsequent
disbursements to the DA will be based on six- monthly estimated expenditure, taking into account the
balance in the DA at the end of each quarterly reporting period and reporting on the use of the
advances previously made. Eskom will also have the option of using: (i) the Direct Payment
disbursement method involving direct payment from the Loan Account on behalf of Eskom to
suppliers of goods and services that have a value above the Minimum Application Size (US$75 million
equivalent); (ii) the Reimbursement disbursement method, whereby Eskom will be reimbursed for
expenditures which it has prefinanced from its own resources and submits withdrawal application for
reimbursement above the Minimum Application Size (US$75 million equivalent); and (iii) the Special
Commitment method whereby the Bank at the request of Eskom, will issue special commitments to
suppliers of goods under the Bank financed components above the Minimum Application Size (US$75
million equivalent).
35.
Other financiers’ flow of funds and disbursement arrangements. Amounts proposed to be
financed by different financiers for the different project components are detailed in Annex 5. AfDB
will advance their funds directly into Special Accounts. It is also expected that funds from other
financiers will flow directly into one of the Eskom’s bank accounts in South Africa or as otherwise
designated. The flow of funds from these financiers will be described in their respective loan
documents.
145
36.
Retroactive financing. A retroactive financing arrangement of up to 10.67% of loan amount
(up to US$400.00 million) will be provided to cover payments made prior to the signing of the Loan
Agreement but on or after January 1, 2007, for all eligible expenditures financed by the Bank loan.
Figure 1: Flow of Funds
AfDB
Other Financiers
IBRD
Withdrawal
Application
with IFRs
Designated Account
(maintained by Eskom)
Special Accounts
(maintained by Eskom)
Eskom
Bank Account
Contractors, suppliers and service providers
37.
Use of Loan Proceeds. The following tables show the allocation of the proceeds of the IBRD
Loan. Use of Proceeds for project costs is provided in Annex 5.
Table 3: Allocation of IBRD Loan Proceeds
Category
Amount of the Loan
Allocated
(expressed in USD)
Percentage of Expenditures to be
financed
(inclusive of Taxes)
(1) Goods and works (including supply and installation)
for Part A.1(a) of the Project
1,766,370, 000
100%
(2) Goods, works (including supply and installation) and
non-consulting services for Part A.1(b) of the Project
593,030,000
100%
(3) Goods, works and non-consulting services for Part
B.1of the Project
80,000,000
100%
(4) Goods, works and non-consulting services for Part
B.2 of the Project
150,000,000
100%
(5) Goods and works for Part C.1 of the Project
319,550,000
100%
(6) Consultants’ services for Part C.1, C.2 and C.3, and
non-consulting services for Part C.1 of the Project
51,000,000
100%
(7) IBRD Interest During Construction
400,000,000
100%
(8) Other Lender Interest During Construction
150,000,000
-
(9) Unallocated
230,675,000
-
9,375,000
Amount payable pursuant to Section
2.03 of the IBRD Loan Agreement in
accordance with Section 2.07 (b) of the
General Conditions
0
Amount payable pursuant to Section
2.07(c) of the IBRD Loan Agreement
(10) Front-end Fee
(11) Premia for Interest Rate Caps and Collars
TOTAL AMOUNT
3,750,000,000
146
Auditing arrangements
38.
Eskom is listed as a Schedule 2 public entity and is regulated by the PFMA to submit annual
report to the Minister of DPE for noting and submission to the Parliament within five months after end
of the financial year. The annual financial statements together with the audit reports are included in
the annual report.
39.
Eskom has an unqualified audit report for year ended March 31, 2009 and is audited by
KPMG Inc and Sizwe Ntsaluba vsp. The statutory auditors for the forthcoming year are appointed at
the annual general meeting.
40.
The annual audit is conducted in accordance with the International Standards on Auditing.
Eskom’s Audited annual financial statements which will include the project financial activities will be
submitted to the Bank within six months of the end of the financial year, that is, by September 30 each
year. The submission will include the auditors’ report, management letter, and management’s response
thereto as an attachment to the FS.
41.
Audited financial statements. Eskom’s audited annual financial statements will be acceptable
to the Bank without a requirement for a separate audit report for the project. Eskom will prepare the
audit terms of reference in consultation with the Bank to ensure adequate coverage of the project in the
scope of the audit. The quarterly interim financial reports (project specific) need not be audited on a
quarterly basis; however, the process and controls to produce these quarterly IFRs will be reviewed to
ensure that its data is derived from SAP and, on a test basis at year-end, the IFRs will be agreed to
SAP. The audited annual financial statements will also reflect all the withdrawals from the loan
account during the period with assertion that the loan proceeds have been used for the intended
purposes and in accordance with the bank legal agreements. The Designated Accounts, into which loan
proceeds are first received and then used for financing of agreed project expenditures, will be included
in the scope of the audit of transactions, accounting, bank reconciliation, financial assets and reporting.
42.
The following table identifies the audit reports that are required to be submitted to the Bank by
the Eskom and the due date for submission.
Table 4: Required Audit Reports
Audit Report
Due date
Continuing Entity Financial Statements- April-March
September 30 each year
Loan Processing
Actions to be taken by Effectiveness: None
Reporting Undertakings:



Maintain the financial management system including records, and accounts in accordance with
the terms of the IBRD Loan Agreement;
Prepare and furnish to the Bank, not later than 45 days after the end of each quarter, interim
unaudited financial reports for the project on a cash basis covering the quarter, in form and
substance satisfactory to the Bank;
Have Eskom’s financial statements audited (incorporating the project financial activities) in
accordance with the provisions of Section 5.09 (b) of the General Conditions. Each audit shall
cover the period of one year and shall be submitted to the Bank not later than six months after
the end of the Government’s fiscal year, that is, by September 30 each year; and
147
Supervision plan
43.
Based on the project’s “Low” FM risk rating, the Bank will carry out the onsite FM
supervision of the project at least once a year. In addition, the Bank’s FM specialists will carry out
desk-based quarterly review of the IFRs and the annual audit reports.
Governance and Accountability
44.
Eskom’s governance arrangements and the oversight provided by the Board, Government
through DPE, and other stakeholders, which include the general public, are considered adequate for the
implementation of the project.
45.
The assurance and forensic general manager and the external auditors have unrestricted access
to the chairman of the committee and the chairman of the board.
Overall Conclusion
46.
Based on the proposal to use Eskom’s FM system for accounting and reporting the project
receipts, expenditures and asset management, including commitments, the overall conclusion of the
assessment of the system is that the proposed FM arrangements meet the Bank’s minimum
requirements for financial management under OP 10.02.
148
Annex 8: Procurement Arrangements
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Project Components
1. Section II.C of PAD provides further details on Project Components.
Implementing Agency
2.
Procurement activities will be carried out by Eskom Holdings Limited (Eskom). Eskom was
established under the Companies Act, 1973 and in 2001 was converted to a Public Company based on
the 2001 Eskom Conversion Act with no change of ownership. The single shareholder of Eskom is the
GoSA, represented by the Minister responsible for Public Enterprises.
Eskom Procurement Capacity and Controls
3.
Eskom has a well-organized procurement system, with qualified and capable personnel.
Organization of the procurement function comprises separate arms for policy, strategic sourcing such
as bulk procurement of stock items, and for capital procurement. Eskom’s procurement process is
governed by Eskom’s policies and procedures and the Country’s legal framework to deal with fraud
and corruption.
4.
The organizational structure of Eskom includes a number of Divisions. The Corporate
Regulations, Directives, Good Practices Notes and other documentation, including those pertaining to
procurement, are prepared and issued by the Finance Department in the Corporate Division. The
contracts under the components of the Bank-financed project will be procured and implemented by the
Commercial Department of the Enterprises Division. This Department includes teams responsible for
specific projects, e.g., Medupi, Majuba Rail, Wind Farm, Solar, Refurbishment, etc., as well as the
supporting departments such as Strategic Sourcing, Evaluation, Negotiation, etc. The Commercial
Department is staffed with 350 officers of whom 190 are dedicated to procurement. Procurement
activities are supervised by about a dozen senior Eskom staff.
5.
Eskom’s commercial activities are governed by the Public Finance Management Act (PFMA)
which stipulates that an organisation such as Eskom should have in place “an appropriate procurement
and provisioning system which is fair, equitable, transparent, competitive and cost-effective”. In
addition, a governance structure is in place that allows for a proactive, in-process audit and assurance
framework to be implemented with the objective of providing assurance to the governance structures
that the transaction under review complies with PFMA. As per Eskom’s procurement policies, each
contract has been/or is in process of being evaluated by a third-party independent auditor to confirm
consistency with the Eskom policies and provisions of their bidding documents. In addition to the
PFMA, Eskom is mandated to comply with legislation aimed at preventing fraud and corruption,
public disclosure as well as Black Empowerment laws:
 Promotion of Access to Information Act, No. 2 of 2000
 Prevention and Combating of Corrupt Activities Act No. 12 of 2004
 Preferential Procurement Policy Framework Act No. 5 of 2000
 Promotion of Administrative Justice Act No. 3 of 2000
 Broad Based Black Economic Empowerment Act No. 53 of 2003
 The Construction Industry Development Board (CIDB) Act 38 for 2000
 Construction Industry Development Regulations, 2004
 Standard for Uniformity in Construction Procurement (Standard), January 2009.
149
6.
Consistent with the above legislation, Eskom is guided by several of its own policies and
procedures among which Eskom Procurement & Supply Chain Management Policy and Procurement
& Supply Chain Management Procedure are the most important. An anti-corruption cell is managed by
Eskom which refers any wrongdoing cases to GoSA agencies in charge of ensuring fraud-free
procurements by public agencies.
7.
Eskom has a clearly defined delegation of authority which covers procurement decisions. This
delegation is updated at least every three years.
Procurement under Component A (Medupi Power Plant)
8.
The component consists of : (a) contracts for the Medupi Power Plant procurement which has
been completed or is close to completion; and (b) contracts for the Medupi Power Plant associated
Transmission lines which are yet to be procured.
9.
The procurement action for the Medupi Power Plant was initiated in late 2005. At that time
Eskom and the Government expected Eskom to fund the program through a combination of internal
cash generation and commercial debt, which Eskom could normally have raised on the market with its
strong credit rating and GoSA support. They had no intention of seeking financing from the World
Bank or other multilateral agencies, and therefore had no reason to follow procurement guidelines and
procedures other than their own. The situation changed when a combination of a slower than expected
tariff progression and the global financial crises resulted in major funding shortfalls. The GoSA and
Eskom approached AfDB129, IBRD, and bilaterals among others, to help bridge the financing gap that
emerged after Eskom initiated the contracting for the Medupi Power Plant. Contracts comprising about
80 percent of the plant value have been awarded and the remaining contracts are expected to be
awarded during the first half of 2010.
10.
The Medupi Power Plant comprises various supply & install and construction contracts that
are being undertaken by Eskom as the Employer for a cumulative value of US$9.35 billion, including
about US$765 million of contingencies. Bank financing in an amount of US$2.489 billion (including
contingencies, but excluding any related IDC) is proposed for contracts related to the Medupi Power
Plant (Component A).
11.
Eskom has completed the full procurement process — bids have been evaluated and contracts
have been awarded for about US$7.5 billion of Medupi related contracts. Of such contracts, Bank
financing is being considered for US$1,383.72 million. Table 1 provides an overview of the contracts
that have already been awarded.
Table 1: Medupi Power Plant – Supply & Install and Construction Contracts Already Awarded, excluding
additional Contingencies
Name of the Contract
Amount (US$ Millions)
Proposed to be Financed by IBRD, of which
Coal Overland Conveyor
LP Services
Water Treatment plant
Chimney & Silos
Main Civils
Electrical Power Installation
Medium Voltage Switch Gear
1,383.72
28.88
155.93
105.47
118.02
599.24
127.18
39.61
129
Amount of proposed
IBRD financing
(US $ Millions)
1,383.72
28.88
155.93
105.47
118.02
599.24
127.18
39.61
AfDB’s Board approved the loan of US$2.63 billion equivalent on November 25, 2009. The AfDB loan will finance some
of the already committed and procured contracts for the Medupi Power Plant, specifically the Boiler and Turbine contracts.
150
Name of the Contract
Coal Stockyard Equipment
Dust Handling and Conditioning
Other Contracts not financed by IBRD
Total
Amount (US$ Millions)
Amount of proposed
IBRD financing
(US $ Millions)
130.90
130.90
78.49
6,053.68
7,437.40
78.49
1,383.72
12.
The procurement for the other contracts that have begun procurement is estimated to be
US$382.65 million (or about 3.8 percent of the total value of the construction costs), all of which will
be financed by the Bank. For such contracts, bids have been received; most of them have been
evaluated and are in the process of being finalized for award. Table 2 below provides an overview of
these contracts.
Table 2: Medupi Power Plant – Supply & Install and Construction Contracts in Advanced Stages of
Procurement, excluding additional Contingencies
Name of the Contract
Proposed to be Financed by IBRD, of which
Low Voltage Switch Gear
Ash Dump Equipment and Ash Overland
Terrace Coal and Ash System
Uninterrupted Power Supply
Water Reservoirs
Total
Amount (US$ Millions)
Amount of proposed
IBRD financing
80.95
115.72
138.11
20.49
27.38
382.65
80.95
115.72
138.11
20.49
27.38
382.65
Bank’s Due Diligence to establish eligibility of procured Medupi Power Plant contracts for Bank
financing
13.
As the GoSA and Eskom have requested the Bank to finance contracts which have already
been awarded using Eskom procedures (not procured using Bank’s Procurement Guidelines),
independent reviews at the aggregate level and the due diligence at contract level have been
undertaken to establish that (a) the overall procurement meets global industry standards and cost
parameters; (b) all contracts proposed to be financed by the Bank fully comply with Eskom
procedures; and (c) there are no sanctioned firms involved in the Medupi Power Plant contracts
proposed to be financed by the Bank (see details below for the assessments):
a. Aggregate Level: Benchmarking of the outcome of the procurement for Medupi with
similar projects procured at the same time in other parts of the world, to establish
economy and efficiency as per industry standards. The benchmarking of costs of the
plant (at an aggregate level) for similar-size supercritical coal-fired power plants to
establish that procurement was economic and efficient.
b. Contract Level: Due diligence to ensure that the process undertaken for these contracts
has followed Eskom/GoSA policies and procedures and to identify key deviations
from Bank Guidelines. An independent review to ensure that procurement of the
packages has met general principles of industry-wide standards, economy, efficiency
and transparency for this scale and timing of procurement at the time it was carried
out.130
130
As per the requirements of Eskom’s procurement policies, each contract has been/or is in process of being evaluated by a
third-party independent auditor to confirm consistency with the Eskom policies and provisions of their bidding documents.
151
14.
Review at the Aggregate Level: The review has been carried out by Nexant Inc. of USA, a San
Francisco-based engineering consultancy firm commissioned to establish whether the overall
procurement process for the Medupi Power Plant met general principles of industry-wide standards of
economy, efficiency and transparency for this scale and timing of procurement. In so doing, the
Consultant has also been requested to benchmark the costs of the Plant for similar size supercritical
coal-fired power plants in the world. The following paragraphs summarize the consultants’ findings:
15.
Opinion on the design: The design basis for the Medupi plant is specified in Eskom’s User
Requirement Specifications (URS) document. Eskom prepared the URS document to provide design
specifics pertaining to all major equipment and systems with the lowest possible life-cycle cost for the
plant, while meeting the reliability and performance goals. Nexant reviewed the URS document
including design parameters, unit load factor, unit capacity factors, station thermal efficiency, net
output, plant equipment redundancy, etc. The URS meets or exceeds performance, reliability and
availability requirements of similar coal-fired plants in operation or being constructed today. Eskom’s
overall plant design, steam cycle optimization, and plant layout are consistent with the current
engineering design practices for coal-fired power plants and the plant design performance is in line
with similar supercritical plants in operation or being built. Current international standards in most
countries require that coal-fired power plants use best available control technology to control SOx,
NOx, and particulate emissions. The URS specifies utilizing low NOx burners for NOx control, baghouse filters for the particulate control, and FGD at a later date for SOx control, when additional water
will be available at the Medupi site.
16.
Opinion on procurement: Eskom decided to execute the Medupi project under a multi-contract
strategy. For the Medupi project, Eskom’s Enterprises Division divided EPC work into 38 separate
EPC contracts. Since boiler and turbine procurement constitute over 50 percent of the overall Medupi
project costs, and will have significant influence on the plant performance and life-cycle costs, Nexant
evaluated Eskom’s efforts in procuring boilers and steam turbines for the 6 Medupi units. Although
Eskom made significant efforts to receive bids from as many credible vendors as possible, in the end
only two major manufacturers met the technical requirements and submitted qualifying bids meeting
large sized power plant requirements, local content in country skills development, and desired project
schedule.
17.
Eskom’s Tendering experience for the supply of the six boilers and steam turbine generator
units for Medupi project underscores the very competitive world-wide power plant equipment and
components market that existed from 2005 through 2008. In 2006, during Eskom’s Tendering period,
the international market for 800 MWe boilers was essentially sold-out. As an example of the world
market conditions, Texas Utilities (TXU) in the United States awarded on June 8, 2006 the supply of
eight (8) identical supercritical coal-fired boilers of 858 MWe capacities to Babcock & Wilcox
Company for delivery from 2007 through 2010. This award committed all of B&W’s 800 MWe boiler
production from their US and China manufacturing plants for the subsequent four years.
18.
In addition, Eskom’s location at the tip of Africa, along with the fact it had not been active in
the international market for large power plant equipment since 1989, meant that it was not the most
attractive market for the suppliers. This notion is also corroborated by procurement carried out under
Bank financed projects in Africa over the last few years, where energy projects have not generated
substantial participation from international suppliers because of commitments in developed parts of the
world, which is a preferred market for suppliers.
19.
Nexant’s observation of large power plant development during 2005-2008, when Eskom was
planning the Medupi project, can be summarized as follows:
a. The global demand for power plant components was confirmed to be very high
and implementing agencies were facing significant bottlenecks.
b. Production capacity was globally under pressure.
152
c. Availability of specific commodities such as specific types of high-strength steel
was under pressure; long lead times for components were negatively affected as
well.
d. Skilled manpower was in short supply, including disciplines such as labor,
commercial, financial and technical (engineering).
20.
In Nexant’s opinion, Eskom’s overall procurement process, although drawn out, in the end
proved to be fair, transparent, and in compliance with the existing laws of South Africa.
21.
Opinion on project cost benchmarking: Since no large coal-fired power plant has been built in
recent years in Africa, Nexant does not have benchmark costs for Africa. The benchmarking effort was
based on available and published data for the North America, EU, and South East Asia markets.
Nexant excluded the Chinese power market from benchmarking due to limited information available,
and the lack of export projects with Chinese supercritical equipment in 2005-2007.
22.
Nexant has opined that the total base project cost for the Medupi Power Plant is comparable to
US market and is on the low end of the EU market (without the FGD). However, Eskom’s costs are
higher131 when compared to plants being constructed in India and China – largely based on East Asian
and Indian suppliers.132 The latter are not representative of the international markets as cost data are
only available for domestic plants and virtually no export orders were concluded by the Chinese
manufacturers for similar equipment at the time.
23.
The worldwide competition for power plant design and construction resources, commodities
and equipment was driven mainly by huge demand for power plants in China and India, by a rapidly
increasing demand for power plants and pollution control modifications in the United States required
to meet SO2 and NOx emissions standards, and by the competition for resources from the petroleum
refining industry.
24.
In Nexant’s opinion, Eskom has assembled a capable team to execute the construction of the
Medupi project and is executing the project well.
25.
Review at the Contract Level: The Bank commissioned an independent retiree consultant (exchair of the OPRC) to support Bank Procurement Specialists in carrying out due diligence and to
ensure that the procurement process undertaken for each of the contracts proposed to be financed by
the Bank has followed Eskom/GoSA policies and procedures. Due diligence for the contracts which
have been signed has been completed. Eskom will submit the documentation of the remaining
contracts as soon as they are signed, and their eligibility for financing will be subject to the same due
diligence.
26.
The review of the procurement processes (largely completed) has concluded that the
procurement process followed by Eskom, although not having full compliance with the Bank’s
guidelines, was transparent, focused on economy and efficiency, gave the same opportunity to several
bidders from developed and developing countries, and included procedures to encourage development
of domestic contractors (as well as minorities, like black persons and women).
27.
The review of the procurement processes revealed areas of divergence between the Bank’s
procurement procedures and Eskom’s procedures. Some of the key deviations include: (a) Eskom uses
own bidding documents with modified FIDIC conditions of contract, which do not have fraud and
131
Estimated by up to 40 percent on some contracts.
Increases in construction costs, particularly during the 2004-2008 time period, were experienced by coal-fired power
plants. This was in large part due to a significant increase in the worldwide demand for power-plant design and construction
resources, commodities and equipment. The limited capacity of EPC firms and equipment manufacturers also contributed to
high construction costs. This also meant fewer bidders were at available, higher prices and front loaded payment schedules
were quoted with longer delivery times. The demand for and cost of both on-site construction labor and skilled manufacturing
labor have also escalated significantly in recent years.
132
153
corruption and right to audit clauses as required by the Bank; (b) bids are opened in public, prices are
not read out; (c) negotiations conducted with the lowest evaluated bidder; (d) merit point system is
used to evaluate bids for works; (e) Accelerated Shared Growth Initiative of South Africa (ASGI-SA)
and Competitive Supplier Development Program (CSDP) are taken into consideration in the evaluation
of bids; (g) use of registration of bidders grading firms based on the capability criteria as a condition of
prequalification and contract award; and (h) parent company guarantees are required.
28.
The analysis of the deviations from Bank procedures as observed in Eskom procedures
concluded that these procedures were well established and transparent, and entailed economy and
efficiency. The following provides a summary of the analysis carried out:
a. Considering that the company had not carried out large-size procurement (similar to
the size of Medupi) for many years and thus had limited knowledge of the contractors’
and suppliers’ market, for the purposes of Medupi procurement, Eskom created
possibility of competition by either advertising bidding opportunities or directly
inviting a wide representation of potential bidders.
b. The due diligence of contracts proposed for Bank financing revealed that the outcome
of the evaluation of bids would be the same if such bids were evaluated using the
criteria following the Bank’s Guidelines.
c. While the GoSA’s law requires bidders’ registration and application of the national
preferential policies, the Bank is not aware of any complaint against such registration.
Due diligence has identified that in the procurement processes for boilers and turbines
contracts that Sumitomo and Doosan Heavy Industry declined to submit a tender for
either package because they indicated their inability to comply with South African
National Industrial Participation Program (NIPP) and Black Economic Empowerment
(BEE) requirements included in the tender documents.
d. Negotiations were carried out within the scope authorized by Eskom’s management
and included clarifications of the bids.
e. Eskom requires bidders to submit a parent company guarantee in addition to the
performance security. Such guarantees are also considered to establish bidders’
financial credibility by Eskom. The Bank’s Guidelines require bidders to provide
evidence of their financial capability on their own account without relying on the
parent companies.
154
Box 1: South Africa’s preferential policies that support those previously disadvantaged and develop
competitive ancillary suppliers
A. ASGI -SA (Accelerated Share Growth Initiative)
ASGI-SA is an initiative and policy of the GoSA, initiated in 2004, to accelerate economic growth by 6 percent and to halve
poverty and unemployment by 2014. ASGI-SA is fully aligned with GoSA’s growth, poverty eradication and job creation
strategy. Public Agencies are required to set local content for black economic empowerment (BEE, BWO and SME) and
skills development targets as key evaluation criteria in tenders that it awards.
BEE (Black Economic Empowerment)
Black Economic Empowerment has been a major policy initiative of the South African Government since 1994 and has now
been formalized in legislation. BEE was introduced to promote access to mainstream businesses by Black suppliers, enhance
entrepreneurship and maximize the purchase from previously disadvantaged persons. Suppliers are assessed on a set of
criteria – either BEE, SME (Small Medium Enterprises) or BWO (Black Women Owned). In 2007 Eskom amended its BEE
policy to be in line with BBBEE Codes discussed below.
BBBEE (Broad Based Black Economic Empowerment)
GoSA’s policy to promote black business and the economic upliftment of black South Africans is enacted into law through
the Broad Based Black Economic Empowerment Act 53 of 2003. The aim of this Act is to promote the achievement of the
constitutional right of equality, and increase broad based and effective participation of black people in the economy. The
BBBEE Act does not set penalties for non-compliance but requires that BBBEE is considered by all organs of state such as
Eskom in taking procurement decisions. Since 2007, under the BBBEE Codes seven criteria including ownership,
management, employment equity, preferential procurement, and CSI are used to measure BBBEE within a company or
organization.
B. CSDP (Competitive Supplier Development Programme)
CSDP is an initiative and policy of the South African Government aimed at developing sustainable local industry in South
Africa. CSDP was introduced in 2007 by the Department of Public Enterprises (DPE) with the objectives to: (a) stimulate
local industries to exploit the opportunities arising from global shortages of certain components; (b) develop new local
industries; (c) increase the capacity and capabilities of existing local industries; (d) increase the competitiveness of local
industries; and (e) develop export capabilities and export opportunities for local industries. This is an alternative means to
achieve the goals of the NIPP (see below). Eskom has chosen to implement the CSDP instead of the provisions of NIPP
directly.
NIPP (National Industrial Participation Programme)
The National Industrial Participation Program is an initiative and policy of the South African Government initiated in 1997.
The objectives of the program are to establish new trading partners and foreign investment in South Africa. State owned
enterprises may however elect in certain circumstances to implement CSDP as an alternative to the NIPP. Under the NIPP,
Government and State Owned Enterprise awarded contracts with an imported content equal to or exceeding US$10 million
(or the equivalent thereof) are subject to an Industrial Participation Obligation. The obligation is 30 percent of the imported
value of the contract to be invested in local economy.
29.
Due Diligence on Fraud and Corruption (F&C) and Audit Rights: The contractual clauses in
the modified FIDIC documents that Eskom is using for Medupi procurement do not provide the Bank
exactly the same rights with respect to Fraud and Corruption as the Standard Bidding Documents
(SBDs) of the Bank. To this extent, Eskom has agreed to incorporate such rights (for the Bank) in the
contracts awarded133 for the Medupi Power Plant. Eskom has begun the process of including these
clauses (consistent with Bank requirements on Fraud and Corruption and Audit Rights) in the contracts
already awarded or currently being finalized. The Bank will not finance any contracts which do not
include its Fraud and Corruption related clauses. In case the Bank’s determines an occurrence of any
violation of the Bank’s fraud and corruption provisions, Eskom will promptly inform the affected
contractor(s).
30.
It is not possible to obtain Audit Rights for the bidders who were not selected as they do not
have any obligations to Eskom. The Bank, therefore, will not have Audit Rights on such bidders. 134
To this extent, the Bank has reviewed the legal framework for F&C in South Africa and is comfortable
133
These include only those contracts that are proposed to be financed by the Bank.
These Audit Rights to permit the Bank to inspect their accounts and other records relating to the bid submission arise out
of provisions in the Standard Bidding Documents. Also refer to Paragraph 1.14(e) of Procurement Guidelines.
134
155
that Eskom and the GoSA have rights to pursue any F&C allegations or procurement-related
complaints.135 136 However, as a measure of abundant caution, the Bank has also received an assurance
from the GoSA and Eskom to cooperate with the Bank, based on South African law, in case the Bank
is required to pursue F&C allegations or suspicion with regard to the procurement process of any of
the contracts proposed for Bank financing. GoSA and Eskom have committed themselves to ensuring
their full support to the Bank to investigate any issues as and if they arise. A legal covenant to this
effect has been negotiated in the IBRD Guarantee and the IBRD Loan Agreement. Moreover, in the
event the Bank finds any misrepresentation of information from Eskom it would have the right to
cancel the loan disbursed for the contract.
31.
Eskom has provided the Bank with a list of Contractors and Subcontractors for the contracts
already awarded and are proposed for IBRD financing. The Bank will ensure that the firm chosen is
not and was not at time of award or contract signing on: (a) the Bank’s Debarred List of firms; or (b)
Temporarily Suspended List of firms. Contracts awarded to firms debarred or suspended by the Bank
or not including debarred or temporarily suspended subcontractors/subsuppliers will not be eligible for
the Bank financing.
32.
For the purposes of implementation of contracts, Eskom has established a procedure of
checking new subcontractors/subsuppliers that may be proposed by the contractors after the date of the
lists already delivered to the Bank to ensure that Eskom does not approve a debarred or temporarily
suspended firm as a new subcontractor or subsupplier.
33.
Conclusion: Based on the satisfactory completion of the above-mentioned review and due
diligence including the benchmarking and compliance check to ensure that procurement of the
contracts has met general principles of industry-wide standards of economy, efficiency and
transparency for this scale and timing of procurement, and the incorporation of F&C and Audit Rights
provisions in the contracts, Board approval is sought to finance the contracts for the Medupi Power
Plant already awarded by Eskom under Component A using Eskom/GoSA procedures which are not
fully consistent with Bank’s Procurement Guidelines. The one-time exception is being sought for
application of the Bank’s Procurement Guidelines (not Consultant Guidelines) only for the Medupi
Power Plant contracts (excluding Medupi future contracts) under Component A of the proposed
project.
34.
The alternative would be to seek rebidding of the identified and already procured contracts,
which is not feasible; any rebidding of such contracts would result in major contractual consequences
(penalties etc.) and lead to unacceptable delays. Rebidding of contracts which are yet to be awarded
has serious consequences as well. Despite major contracts being awarded, the plant would not be able
to reach commissioning without the goods and equipment yet to be awarded and therefore rebidding
would result in a delay of at least 2 to 3 years in the commissioning schedule for the project. The
Medupi Power Plant’s generating capacity when commissioned will account for nearly 12.5 percent of
the current generation capacity in South Africa. If the commissioning of the plant which is expected in
August 2015 (all units) is delayed to 2018, it will have serious impacts on the South African economy
and that of the subregion.
Remaining Procurements under Components A (Medupi Power Plant contracts and related
Transmission Lines ), Component B and Component C of the Project
35.
Procurement for the supply&install and construction contracts for the Power Plant and
associated transmission under Component A, as well as procurement for Components B and C, would
135
Eskom does not register procurement process related complaints and provides such complaints to other GoSA agencies for
further action.
136
In this connection, a legal option from Eskom’s independent counsel is a condition of effectiveness of the IBRD Loan.
156
be carried out in accordance with the World Bank’s “Guidelines: Procurement Under IBRD Loans and
IDA Credits” dated May 2004, revised October 2006; and “Guidelines: Selection and Employment of
Consultants by World Bank Borrowers” dated May 2004, revised October 2006, and the provisions
stipulated in the Legal Agreement.
36.
Eskom will carry out procurement using the Bank’s Standard Bidding Documents for all ICB
and the Bank’s Standard Request for Proposals for selection of consultants. For procurement of nonconsulting services Eskom will use the Bank’s sample Bidding Documents unless agreed otherwise.
37.
For multiple contracts of similar works Eskom will consider inviting bids under alternative
contract options that would attract the interest of both small and large firms, which could be allowed,
at their option, to bid for individual contracts (slices) or for a group of similar contracts (package). All
bids and combinations of bids shall be received by the same deadline and opened and evaluated
simultaneously so as to determine the bid or combination of bids offering the lowest evaluated cost to
Eskom.
38.
Short lists of consultants for services estimated to cost less than US$500,000 equivalent per
contract may be composed entirely of national consultants in accordance with the provisions of
paragraph 2.7 of the Consultant Guidelines.
39.
The Construction Industry Development Board (CIDB) Act and the Construction Industry
Development Regulations: CIDB is mandated by the CIDB Act and the Construction Industry
Development Regulations to register contractors for construction works. Public entities are not
allowed to sign contracts with unregistered contractors. The contractors are registered for the grading
designation and category of construction works based on their financial capability evidenced by
contractor’s annual turnover and available capital, and works capability. The works capability is
determined based on the performed contracts and the number of registered professionals by
professional statutory bodies in accordance with the law relevant to the class of construction works, for
example for engineering by Engineering Council of South Africa (ECSA) or for construction works by
South African Council for Project and Construction Management Professions (SACPCMP).
40.
The CIDB registration process, which is independent from the bidding process is acceptable
with the implementation of the agreed following mitigation measures: (a) evidence of having applied
for CIDB registration shall be required at the time of bidding; (b) CIDB commitment to register firms
within 21 days on a best efforts basis; (c) ECSA and Eskom will work together to fast track
registration of international engineers within a 4 month period based on receiving a complete
application for registration; and (d) full and complete registration is neither a bid qualification criterion
nor part of evaluation criteria for bids.
41.
Eskom will inform potential bidders about the registration requirement in the General
Procurement Notice (GPN) so that they can undertake registration much in advance of the specific
procurement process.
42.
Fulfilling the provisions of the CIDB Act, which mandates CIDB to “promote, establish or
endorse… uniform standards… to regulate the actions, practices and procedures of parties engaged in
construction contracts,” CIDB issued the Standard for Uniformity in Construction Procurement. This
Standard defines procurement procedures, methods, procurement documents, and evaluation formulae
using the scoring evaluation system. These methods, procedures and documents, and formulae are not
compliant with the Bank’s Procurement Guidelines and procedures. GoSA has agreed that Eskom will
not apply the Standard of Uniformity but will apply the Bank’s Procurement and Consultant
Guidelines.
43.
Accelerated Shared Growth Initiative of South Africa (ASGI-SA) is an initiative of the GoSA,
initiated in 2004, to reduce poverty and inequity by steady improvement in the economy's performance
and job-creating capacity. The Constitution of South Africa has affirmative action provisions in the
157
137
procurement undertaken by the State or its institutions for advancement of previously disadvantaged
persons or categories of persons. One of the objectives is to advance Black Economic Empowerment
138
It is in this context that public agencies, including Eskom as a wholly
(BEE, BWO, LBS and SBE).
state-owned enterprise, are required to seek local content and skills development targets as key
evaluation criteria in tenders that they award. Such practice does not align with the Bank’s
procurement policy as it does not fall under the Bank’s Domestic Preference provisions.
44.
General Procurement Notice and the bidding documents would inform bidders to propose the
local content with participation of BWO, LBS and/or SBE. Furthermore, the entire ASGI-SA
framework and benchmarks, as well as the score-sheets for benchmarking, would all be designed ex
ante in the bidding documents (based on Bank SBDs). Participation in ASGI-SA would not be a
criterion for qualification or evaluation. The proposed solution put forward would offer bidders
wishing to participate in the ASGI-SA initiative the following two incentives that would only apply
post award: (a) marginally modified payments terms to release 5% of the Contract Price at an earlier
stage; and (b) a lower percentage of the Performance Security at 5% of the contract price instead of the
usual 10%. In this context, it is important to note that the experience of Eskom and GoSA with ASGISA is that ASGI-SA entails additional costs to bidders; these incentives (which are considered to be
small) were originally introduced to cover these additional costs, e.g., the cost of skills development
(which is one of the ASGI-SA elements) and equivalent to training provided within the scope of a
contract.
45.
The Bank has reviewed a set of bidding documents for supply and install single responsibility
contract prepared by Eskom at the Bank’s request which included the above methodology and based
on the Bank’s SBDs with changes as permitted by the Procurement Guidelines (paragraph 2.12).
However, a change in contract terms post-award that provides an incentive through availability of
more favorable contract payment terms, which would not be taken into account in the evaluation, but
which potentially could affect equal opportunity of some bidders (local or foreign) is not contemplated
in the Bank’s Procurement Guidelines. However, it is the Bank’s assessment that the risk of
occurrence of such a scenario is low for the type (highly specialized engineering equipment) and size
(US$ 20-50 million each) of contract packages, which the future procurement would comprise.
46.
During project implementation, the Bank will exercise due diligence and monitor the agreed
procedure to implement the scheme under Bank-financed contracts to ensure that it does not bias the
procurement process in terms of pricing and participation of foreign bidders vis-à-vis local bidders,
joint-ventures, and established foreign companies in South Africa.
47.
Based on the above and the country-specific considerations noted previously, Board approval
is being sought for the inclusion of the ASGI-SA related provisions as proposed by Eskom. The
approved solution would be used in the procurement of goods, works, and supply & installation
contracts.
48.
Eskom also requires its bidders to disclose their level of BEE.
49.
Remaining Procurements under Component A – Medupi Supply&Install and Associated
Transmission Lines. Procurement for the remaining contracts (including associated transmission lines)
137
With consideration of key values of fair, equitable, transparent, economic and cost-effective procurement system
mandated by the South African Constitution, the Constitution provides for the public entities to use categories of preference,
and protection or advancement of persons disadvantaged by unfair discrimination. This builds on the principles laid down in
the preamble to recognize injustice of the past, honor those who suffered for justice and to make South Africa for all united in
their diversity. This builds foundation for South African legislation on preferential policy allowing implementation of the
preferential policy for the previously discriminated persons.
138
BEE - black economic empowerment, BWO - Black Woman Owned Enterprises, LBS - Large Black Suppliers, SBE Small Black Enterprises
158
under Component A is estimated to cost US593.03 million (excluding contingencies). There shall be
multiple contracts procured using a one-stage procedure and the Bank’s S&I SBDs.
Table 3: Medupi Power Plant – Supply & Install and Construction Contracts, where Procurement Process
has not begun, excluding additional contingencies
Name of the Contract
Proposed to be Financed by IBRD, of which
Ash Dump and Dams
Buildings
Associated Transmission Lines
Total
Amount (US$ Millions)
Amount of proposed
IBRD financing
221.61
129.33
242.09
593.03
221.61
129.33
242.09
593.03
50.
Component B.1 – Sere Wind Power Project. While there is adequate procurement capacity in
Eskom for this sub-project, the technical team was earlier disbanded; and will be re-established soon.
There is some experience in Eskom with regard to procurement of wind farms. Eskom previously
advertised the EPC contract for the wind farm and failed to obtain competitive bids. As Eskom lacked
financing at that time, the process was cancelled.
51.
Component B.2 – Upington CSP Project. While there is adequate procurement capacity in
Eskom for this sub-project, the technical team was earlier disbanded; and will be re-established soon.
Unlike Sere, where the technology is better understood, Eskom has initiated a review of its CSP design
in the context of global developments so as to ensure that optimal designs are used. Upon the
completion of this review by international consultants, Eskom proposes to begin the procurement
process for the project. Therefore, a detailed Procurement Plan for this sub-project has not been
prepared. It is expected to be prepared in the second half of 2010 and agreed with the Bank. Given
the innovative technology, Eskom may consider to procure the plant through the EPC or DBOT
contract using a two-stage procedure.
52.
Component C.1 – Majuba Rail Project. There is adequate capacity both for procurement and
technical implementation of the project. The Majuba Rail Team has prepared the cost estimate with a
detailed cost breakdown and the Procurement Plan. Procurement will include mostly works contracts
and some S&I contracts which may use the S&I SBD either for the Plant and Equipment or for the
Information Systems, whichever is deemed more appropriate. Procurement also includes contracts for
non-consulting services which will be procured through ICB.
53.
Component C.2 – Technical Assistance for Efficiency Improvements of the Coal Fleet. The
technical assistance for coal-fired power plant efficiency improvements includes only consultancy
contracts. One contract to be procured within the first 18 months of project implementation is included
in the Procurement Plan. Future contracts will be planned and included in the revision of the Plan in
due course.
54.
Component C.3 – Technical Assistance for Implementation of the Upington CSP and for
domestic and cross-border renewable energy projects. The technical assistance proposed in this
subcomponent includes only consultancy contracts. Three contracts are to be procured within the first
18 months of Project implementation and are included in the Procurement Plan. Future contracts will
be planned and included in the revision of the Plan in due course.
159
Procurement Risk Assessment
55.
The key risk concerning the procurement already carried out is the Reputational risk
emerging from a complaint from firm(s), which learn about Bank financing of the Medupi Power Plant
contracts, and which may allege fraud and/or corruption or other issues not known to the Bank during
its due diligence.
56.
The procurement already carried out was subject to GoSA/Eskom procurement policies and
procedures. In the event of a complaint as stated above for such contracts, any consequent
misinterpretation of facts by Eskom, and/or establishment of fraud, corruption, etc., the Bank has the
right not to finance the concerned contract(s) and cancel the amount allocated for such contract from
the loan. If the amount would have already been disbursed, its reimbursement shall be requested. A
legal covenant to this effect has been negotiated in the Loan Agreement.
57.
Most of the issues/risks concerning the procurement to be carried out for implementation of
the project have been identified and include:
(i)
(ii)
Eskom has no experience in carrying out procurement based on the Bank’s
Procurement Guidelines and Procedures and this may lead to:
a.
delays in the procurement process;
b.
Eskom’s procurement practices, which are different from the Bank’s
Procurement Guidelines and Procedures, making their way into the
procurement of the Bank-financed contracts;
Delays may occur in commencing procurement and implementation of the Wind Farm
and CSP projects due to delays in establishing the technical teams for the projects.
Proposed corrective measures, some of which Eskom has already implemented include:
(i)
Eskom has assigned two senior procurement staff to be responsible for procurement
under the Project and its compliance with the Bank’s Procurement Guidelines and
Procedures.
(ii)
One set of the Bidding Documents has been submitted by Eskom to the Bank. These
Bidding Documents, including the proposed provisions related to ASGI-SA have been
reviewed and commented on by the Bank; and will be agreed with Eskom and shall
serve as model documents for the remaining procurement.
(iii) The majority of the contracts will be subject to the Bank’s prior review due to their
large value, which will allow for timely correction whenever necessary.
(iv)
The Bank will conduct the Project Launch Workshop dedicated to the specific Project
requirements and will advise Eskom on procurement (excluding its participation in the
evaluation process).
(v)
Eskom has developed a complaints handling system which has been reviewed by the
Bank.
(vi)
To the extent possible Eskom will review its approval chain, with the intention of
eliminating inefficiencies. In any case, Eskom will factor in the time taken for all
approvals in the Procurement Plan to ensure it is realistic.
58.
The overall project risk for procurement is Substantial and the residual risk after
consideration of the corrective measures is Substantial. The Bank will continue to closely monitor the
implementation of the corrective measures, which will mitigate the identified risks, and the residual
risk may be adjusted during Project implementation.
160
Procurement Plan
59.
Eskom has developed an appropriate Procurement Plan for project implementation which
provides the basis for the procurement methods. For each contract to be financed by IBRD loan, the
different procurement methods or consultant selection methods, the need for prequalification,
estimated costs, prior review requirements, and time frame are agreed between the Borrower and the
Bank project team in the Procurement Plan.
60.
The Procurement Plan will cover the first 18 months of procurement. This agreed Plan will be
available at Eskom’s offices during implementation and on the Bank’s external website. The Plan will
be updated in agreement with the Project Team annually, or as required to reflect the actual project
implementation needs and improvements in institutional capacity.
Procurement Methods
61.
It has been agreed with Eskom that no National Competitive Bidding (NCB) shall be used
and all contracts shall be procured through ICB through the following methods:
Contracts for goods, works, and non consultants services
1
a
2
a
3
a
Goods
International Competetive Bidding [ICB]
Works and Supply & Install
International Competitive Bidding [ICB]
Non-consultants services
International Competitive Bidding [ICB]
For contracts estimated to cost
All
For contracts estimated to cost
All
For contracts estimated to cost
All
Contracts for consultants services:
4
a
b
Firms
CQ
Other methods
For contracts estimated to cost
Less than US$100,000
US$100,000 or more
No employment of individual consultants is envisaged
62.
Domestic preference shall be used in procurement of Goods contracts.
Prior review
63.
For Component A – the Medupi Power Plant: The Bank carried out its due diligence to
establish the eligibility of the contracts for Bank financing as concluded in Paragraph 31 above.
However, the procurement process has not yet been completed for all contracts proposed for Bank
financing and their eligibility for financing will be subject to the same due diligence.
64.
For Component A Associated transmission lines, Components B and C: All contracts above
the prior review thresholds noted below will be subject to the Bank’s prior review as per Appendix 1
of the Bank’s Guidelines.
161
Prior review thresholds for contracts for goods, works, and non consultants services
1
Goods
Contracts estimated to cost US$0.5 million or more
2
Works and Supply & Install
Contracts estimated to cost US$10 million or more
3
IT systems and non-consultants services
Contracts estimated to cost US$3 million or more
4
Direct Contracting
All
Prior review thresholds for contracts for consultants services:
5
Firms
Contracts estimated to cost US$1 million or more
6
Single source
All
65.
The prior review thresholds in the above table are determined by the aggregate value of all
contracts (slices) in the package or per contract if bid individually.
66.
Contracts which are not subject to prior review shall be subject to post review. The Bank may
also decide to carry out an Independent Procurement Audit which may include both post and prior
review contracts.
Eskom Implementation Arrangements – Procurement matters
67.
Implementation arrangements will be based on the existing organizational structure of
Eskom. The normal sequence of preparation and implementation activities to build and commission
the Project shall be followed. Eskom will issue an internal memorandum (good practice note) to ensure
that any special actions, outside the normal practice for any of Eskom’s investments projects, are taken
in a timely manner.
162
Annex 9: Economic Analysis
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Introduction
1.
Based on South Africa’s Long-Term Mitigation Scenarios (LTMS), the Government has
adopted mitigation strategies aimed at allowing emissions to grow in the short term, albeit at a reduced
rate, plateau by 2030, and decline gradually thereafter. Mitigation strategies include accelerated energy
efficiency across all sectors, investment in new clean energy resources and energy use behavioral
change and the pursuit of regulatory mechanisms and economic instruments. South Africa and Eskom
are committed to this long-term strategy and this operation forms part of this strategy.
2.
In the short to medium- term, South Africa needs to deliver adequate power supply to continue
meeting its poverty alleviation goals and economic development objectives. This assessment finds that
it cannot meet national electricity use needs without addition of baseload capacity in the short-term,
and that the most economically viable option is the development of the Medupi coal-fired project.
Over the next 20 years, according to the LTMS, South Africa’s GHG emissions are expected to
increase by 500 million tons, and Medupi would account for 6.8 percent of this growth in CO2
emissions. Consistent with South Africa’s objective of reducing the rate of growth, the project will
adopt supercritical technology as an initial step in reducing the carbon intensity of the power sector.
3.
In line with South Africa and Eskom’s commitment to reduce GHG emissions, this operation
also supports investments in two other components: (a) Renewable Power Plants - wind and
concentrating solar power (CSP) projects are being developed primarily to help deliver on South
Africa’s commitment to follow mitigation strategies set out in the LTMS; and (b) the Majuba Rail
Project, which would not only reduce GHG emissions as a result of traffic transferring to the more
fuel-efficient rail system, but also result in operating-cost savings for the traffic diverted to the new
line. These projects would help South Africa start to reduce growth in emissions immediately and is
also expected to play a catalytic role for the larger scale development of these technologies in the
future.
4.
The economic analysis has been carried out for all the three components separately, and for the
project as a whole. The economic assessment for the Project covers the following main aspects:
 Assessment of whether additional baseload power is required and whether Medupi
currently represents the least cost option to deliver the required power. If so, assessment of
Medupi’s economic net present value.
 Assessment as to whether the renewable energy projects (wind and CSP) are economically
viable (using a combination of economic rates of return, economic net present value and other
available information).
 Assessment as to whether the Majuba railway project is economically viable (principally
using analysis of economic rates of return from the project and economic net present value).
5.
Calculating economic rates of return (ERR) – consumer willingness to pay (WTP): The total
economic benefits of the projects are assessed using the value consumers place on consuming
incremental power (represented by the area under consumer demand curve). The ERR has also been
evaluated at the present (subsidized) tariff, and just approved tariff with increases of 24.8% in FY11;
25.8% in FY12; and 25.9% in FY13. Tariff increases required in FY14-FY19 in order for the ERR to
163
equal the hurdle rate have also been calculated. Assessment of benefits at the tariff provides an
estimate of the lower bound of WTP.139
6.
If Medupi were a small project, and supplied only the first few kWh of this total expected
increase in demand, then in an idealised competitive retail market the energy would be bought by those
with the highest willingness to pay (say small commercial enterprises), and hence the relevant
yardstick is the marginal WTP. Large industrial consumers could meet their demand by lower cost
self generation. But since Medupi is a large project, accounting for more than half the expected growth
in demand, and since in the absence of retail competition there is no way the incremental energy can
be directed just to the consumers with the highest WTP, the energy will go to a mix of customers with
a mix of WTP. Therefore, use of the average WTP is appropriate and ensures a conservative result.
7.
Based on the household electricity survey of rural South Africa,140 average monthly household
expenditure on electricity substitutes is 44 Rand/month.141 According to the study, typical consumption
of rural households once electrified is 85kWh/HH/month.142 From this follows a WTP of 6.5 US
cents/kWh. If one subtracted the 50kWh/month/HH supplied free of charge by Eskom to poor rural
areas, the WTP increases to 15.7 US cents/kWh: given the uncertainties we use the lower value for the
baseline calculation. The total WTP is then calculated by weighting the WTP by the proportions of
power used by each sector. The average consumer WTP for power in South Africa calculates to 17.54
US cents/kWh.
8.
Calculating economic rates of return – discount rate: The discount rate used for the
assessments is 10 percent. A variety of discount rates have been used for economic analysis over the
past decade in South Africa. DME used 11 percent in their 2003 integrated energy plan, but in the
Long Term Mitigation Studies (LTMS) prepared for DME, 10 percent was used (with sensitivities at
15 percent, 3 percent and zero). The National Energy Regulator of South Africa used 12 percent for
purposes of calculating the feed-in tariff for renewables (though with a footnote that they thought a
"more generous discount rate than DME's 10 percent was appropriate for calculating levelized costs
for the FIT").
9.
Including the social cost of carbon dioxide emissions: For each project, the economic
assessment is also carried out incorporating the value of CO2 emissions. For Medupi, this value is
added as a cost of generating power. For each of the renewable energy projects and the railway project,
this value is represented by the avoided cost due to displacement of CO2 emissions (i.e. it is added as
an economic benefit).
10.
The economic value of CO2 emissions: This analysis uses a figure of $29/ton CO2 which is
based on the Stern review143 (See Box presented later in the Annex). The research on the social cost of
carbon is extensive and growing; with a large range of valuations from a small net benefit to several
hundred dollars a ton. Thus, almost any estimate would find some support. Tol’s 2007 meta-analysis
of the peer-reviewed literature, which updated an earlier 2005 meta analysis, cites 211 studies, with a
mean of US$120/ton of Carbon (US$33/ton CO2 for studies published in 1996-2001), and $88/ton of
Carbon ($24/ton CO2 for studies published since 2001). The $29/ton CO2 used for this analysis comes
139
It is a lower bound because valuation at the tariff ignores any consumer surplus. However, because of the difficulty of
empirical verification of WTP and consumer surplus, as a verifiable indicator of WTP an assessment at the tariff is an
important yardstick.
140
Scottish Power PLC, Community Electricity in Rural South Africa: Renewable Energy Grid Assessment, 2005.
141
Total household expenditure is 145-174 Rand/month, but this includes cooking fuels – kerosene, fuelwood and LPG.
Some wood may also be used for heating water, but it seems unlikely that electrification would result in significant use of
electric water heaters in these areas. Most LPG is used for cooking, with small amounts for ironing, water heating and
refrigeration – but only 27 percent of HH sampled used LPG.
142
This is a high rate of consumption by global standards, with 15-40 kWh/HH/month being the typical range in poor rural
areas. However, 50 kWh/month is provided by Eskom free of charge.
143
Stern, Nicholas. 2007. The economics of climate change: The Stern review. Cambridge: Cambridge University Press.
164
from the Stern review144, which states that “the mean value of the estimates of the (2005) study by Tol
was about $29/ton CO2 though the current social cost of carbon might be around $85/ton CO2”145.
Component A – Medupi Coal-fired Project
11.
For the World Bank to support a conventional power generation project, two conditions must
be fulfilled. First, the project must be shown to be in the least cost expansion plan. Second, the
economic returns must exceed the opportunity cost of capital - such that the net present value (NPV)
evaluated at the opportunity cost of capital is positive.
The Immediate Need for Baseload Power
12.
South Africa and Eskom are committed to a long-term strategy that will begin to reduce GHG
emissions after 2025 once a maturing nuclear program and increased reliance on renewables can
account for a larger share of the generation mix. However, in the short and medium term, South Africa
cannot afford not to expand its power supply if its poverty alleviation and economic development
objectives are to be achieved, although it will seek to identify lower carbon options for doing so.
13.
A first question is whether an expansion of baseload capacity could be avoided by DSM and
improved energy efficiency for which there is considerable potential in South Africa. The load
forecasting accordingly includes assumptions for a continuation of the downward trend in electricity
intensity and an aggressive DSM program that by 2019 reduces the load by 15,562 GWh and 3,225
MW. However, the results of the economic analysis show that over the next decade there is no
alternative to meet South Africa’s power needs than to proceed with major additions to baseload
capacity (see Figure 1). Even under the low demand forecast, about 15 GW of capacity is required.
The expansion of baseload capacity cannot be avoided.
Figure 1: Medupi and load growth
Source: Department of Energy, IRP, November 2009.
144
Stern, Nicholas. 2007. The economics of climate change: The Stern review. Cambridge: Cambridge University Press.
Even the $29/ton estimate has come under wide criticism, not least from Tol himself, who notes that the $29/ton figure
was cited out of context, for Tol concluded in the 2005 study that “it is unlikely that the marginal damage costs of emissions
exceed $50/ton of Carbon (US$14 ton CO2) and are likely to be substantially lower than that”.
145
165
Costing the Generation Alternatives to Medupi
14.
The next question is which is the economically the cheapest source of baseload power. The
Medupi Power Plant and the following options have been considered in the economic analysis as
potentially suitable to provide baseload capacity to Eskom. These alternatives and their expected costs
are discussed in detail from Paragraph 46 to Paragraph 66 later in this Annex.







Nuclear, sited on the coast in the Port Elizabeth and Capetown areas;
Wind, sited on the West and East Coast areas;
Open cycle combustion turbine (sited at load centres and therefore without
transmission penalty);
Combined cycle fuelled by imported LNG (coastal location); Combined cycle fuelled
by HFO; Coastal combined cycle fuelled by gasoil;
CSP, sited in the Northern Cape and Northwest. Two variants of this technology are
considered, namely with and without molten salt storage;
Underground coal gasification projects; and
Large hydro, for which the only project of sufficient scale to be considered as even a
(partial) alternative is the Inga -III project in the Democratic Republic of Congo
(DRC).
15.
Comparison of Alternatives: Three main attributes that require consideration in the assessment
of alternatives to Medupi are:



the economic cost, expressed as $/kWh or as the NPV of lifetime costs to supply the
energy provided by Medupi;
the total financing requirement, in $US billion; and
the undiscounted lifetime GHG emissions, in million tons over the assumed 30-year
economic life.
16.
Figure 2 compares the economic production cost of Medupi (5.8 cents/kWh) with its
alternatives, which range from 6.3 UScents/kWh (Inga-III) to 17.9 UScents/kWh (CSP with Storage).
It is clear that Medupi is the least cost generation option for Eskom. Inga III is the second best
alternative; although the delivered cost appears competitive, the uncertainties – geopolitical, financial
and technical – are formidable, and even under optimistic conditions the time frame for significant
power flows to be available to Eskom is 2022 at the earliest.
Figure 2: Levelized Economic Costs of Energy
166
Incorporating Carbon Shadow Prices in Economic Least Cost Analysis
17.
The trade-off between Medupi and its alternatives can also be captured by calculation of the
carbon shadow prices. This is the value of CO2 that would make the alternatives equal based on total
economic costs.
18.
Table 1 provides an overview of the carbon shadow prices for specific alternatives. The table
shows that the carbon shadow prices for the Medupi alternatives are high i.e. a high carbon price
would be required in order for the alternatives to exhibit the same level of viability as Medupi (far in
excess of current carbon market prices146). The only exception is Inga-III hydropower plant in DRC.
As an illustration, in 2008, the average carbon price was $16.8/ton in the primary CDM market, and
$29.7/ton in the EUETS:147 these values have fallen since then to around $12-15/ton.
Table 1: Carbon Shadow Prices, US$/ton
Alternative Projects
Medupi
Hydro (Inga-III)
CCCT(HFO)
CCGT-LNG
Nuclear
CCCT(gasoil)
UCG
CSP, 25% LF
Wind
CSP storage, 40% LF
CSP storage (Upington)148
Production Cost
Carbon Shadow
Price
Lifetime CO2
Emissions
Capital Costs
[US cents/kWh]
$/tonCO2
[millionTonsCO2]
$/kW
5.8
6.3
9.9
9.5
11.0
13.1
14.5
14.8
15.5
17.0
17.9
0
7
156
105
67
275
223
115
124
143
155
769
0
534
387
0
511
508
0
0
0
0
2,253
2,621
1,218
965
4,996
850
2,370
2,225
1,777
4,100
6,466
19.
Figure 3 shows the production costs plus the cost of CO2 valued at $29/ton.149 Only Inga-III
(6.3UScents/kWh) has a total cost lower than Medupi (8.9 UScents/kWh).
146
By way of comparison, the carbon shadow prices for the CSP alternatives examined in the Botswana Morupule B project
are $112/CO2 for CSP with no storage, and $69/tonCO2 with storage.
147
Source: World Bank, State and Trends of the Carbon Market, reports for 2006, 2007, 2008 and 2009.
148
These assumptions are for a full scale commercial project, as given in the Eskom ISEP-12 database for a 1000 MW
project. This has lower costs than the CSP project component described below. The assumptions for CSP (25 percent load
factor) and CSP (40 percent load factor) are based on the international literature, as described above.
149
$29/ton is the lower end of the range of the estimate of the social cost of carbon in the Stern Review. These are discussed
in Section 5 (and see Box 2 for a brief review of the literature on this subject).
167
Figure 3: Economic production costs plus $29/ton
20.
Figure 4 draws a similar comparison, but with a social cost of CO2 valued at US$85/ton (which
is the upper end of the damage valuation in the Stern Review). Only nuclear (and Inga-III) has lower
costs than Medupi, thus clearly denoting that the proposed Medupi Power Plant is the least cost
alternative available to South Africa for development.
Figure 4: Economic Production Costs plus $85/ton CO2
21.
Incremental Carbon Financing Requirements: While the carbon shadow price conveys a
relative measure of GHG efficiency of the alternatives, a more practical measure of the incremental
costs of GHG emission-free alternatives is the amount of finance required to cover the additional upfront investment (through carbon financing or any other means of subsidized funding). Table 2 shows
these requirements for alternatives when compared to the Medupi Power Plant.
168
Table 2: Incremental Finance Requirements
(project scaled in size to deliver the same energy output as Medupi)
Total Estimated Financial Cost
Incremental Finance Requirement
US$ billion
US$ billion
5.5
-9.3
5.5
6.4
10.1
13.0
14.8
34.4
35.4
40.2
48.7
-9.3
-8.5
-4.7
-1.9
Combined Cycle Gas Turbine
(CCGT) LNG
CCCT (gasoil)
CCCT (HFO)
Hydro(Inga-III)
Underground Coal Gasification
Medupi
Nuclear
Wind
CSP
CSP storage (Eskom proposed)
19.6
20.5
25.4
33.9
Conclusions from Economic Assessment
22.
Renewable energy alternatives to Medupi score best on the GHG emission attribute, but have
significantly higher financing requirements, which far exceed what can reasonably be expected from
the presently available carbon financing sources150.
23.
Fossil energy alternatives such as LNG and liquid fuelled CCCTs have lower financing
requirements, and somewhat lower GHG emissions, but have significantly higher fuel costs. South
Africa’s coal reserves of the low quality proposed for powering Medupi have a low economic cost –
and the use of imported fossil fuels incurs large economic penalties for South Africa.
24.
The baseline economic rate of return (ERR) of the Medupi coal project is 24.0 percent, with an
NPV (at 10 percent discount rate) of US$15.72 billion.
25.
The ERR at the existing average tariff (4 UScents/kWh) is negative, which points to the
importance of raising electricity tariffs. Under the tariff increases just approved by the regulator
(24.8% in FY11; 25.8% in FY12; and 25.9% in FY13 (nominal) - and no increases in real terms
thereafter), the ERR increases to 2.47%. Based on a tariff scenario which assumes a 12.5% increase in
FY14 and FY15, and one percent above inflation thereafter, ERR increases to 8.13% (at which point
the tariff is 8.9 UScents/kWh). This result is the lower bound of economic returns given the
consideration that the consumer group with the lowest WTP is large industry (which in the absence of
the power provided by Medupi would use captive generation based on fueloil), and which has a WTP
of around 12 .7 UScents/kWh, thus demonstrating that this is the lower bound. The switching value of
the tariff increase required in FY14-FY19 is 5.4% (excluding inflation) per annum.
26.
Incorporating GHG emission damage costs: Once Medupi is at full output, its gross GHG
emissions are some 33.8 million tons per year. Over the next 20 years, South Africa’s GHG emissions
150
Wind and CSP would require about US$20-25 billion of additional carbon finance, 30-40 times the financing provided by
CTF and IBRD for the wind and CSP components of the proposed project. This level of carbon finance is simply not
available to South Africa in the current financial markets. Whether a wind farm (or farms) of the size envisaged is a realistic
proposition in this time frame is unclear. As of December 2008, the total global installed capacity was 104,100 MW, with
2008 additions of 23,766 MW (Global Wind Energy Council, Global Wind 2008 Report) of which the largest country share
was the USA, with 8,358 MW, followed by China with 6,300 MW. The largest wind farm in the world is reported to be the
732 MW Horse Hollow wind farm in Texas, spread across 47,000 acres of Taylor and Nolan counties.
169
are expected to increase from around 500 million tons CO2 to 1,000 million tons, an increase of
500million tons.151 Medupi will thus account for 6.8 percent of this growth in CO2 emissions.
27.
However, if Medupi were not constructed, it does not follow that emissions would be 30
million tons per year less. Two counterfactuals could be hypothesized. The first, consistent with the
methodology for estimating WTP, is that in the absence of grid-connected electricity consumers would
use diesel self generation (in the non-domestic sectors), and candles, kerosene and dry cells for the
domestic sector. These alternatives are not free of GHG emissions. Indeed, generation in diesels have
typical emission coefficients of 710-740 gm/kWh for gasoil, and 650-700gm/kWh for larger captive
units using heavy fuels. Emissions from coal combustion at a highly efficient supercritical plant are on
the order of 900gm/kWh (gross), resulting in net GHG emissions of 12.8 million tons/year(at full
output).152
28.
In this scenario, the ERR decreases from 24 percent to 21.9 percent when the net increase in
GHG emissions is taken into consideration, and when CO2 is valued at US$29/tonCO2 (based on the
Stern Review, and also equal to the 2008 EU ETS price). However, US$29/tonCO2 is significantly
higher than the 2008 CDM market price (US$16.8/ton in the primary CDM market), though lower than
the Stern Review upper estimate of US$85/ton CO2.
29.
In the second counterfactual, Medupi would simply be replaced by the next best alternative,
which is LNG in combined cycle. This would reduce the GHG emissions of the counterfactual to
around 0.5 kg CO2 /kWh associated with high efficiency gas combined cycle plant – in which case the
net CO2 emissions increase to 16.7 million tons/year at full output. This reduces the ERR to a
somewhat lower 21.5 percent.153
30.
If the US$ 29/ton CO2 were levied as a tax on gross emissions, and recovered by Eskom as a
consumer surcharge, the average consumer tariff would increase 36 percent. If the tax were levied only
on net emissions (i.e. less the tax as might be imposed on petroleum products used in the absence of
grid electricity), then the consumer tariff increase is only 10 percent.154
151
Source: Thapelo Letete, Mondli Guma and Andrew Marquard, Information on Climate Change in South Africa:
Greenhouse gas emissions and Mitigation Options, Energy Research Centre, University of Capetown.
152
When one takes into account T&D losses (which are avoided in captive self-generation), the emissions from coal would be
10 percent higher.
153
The detailed analysis has also assessed Medupi’s gross Nitrous oxide (N2O) emissions. Though emitted in small amounts
as a combustion product, N2O is of concern because of its high global warming potential of 310. The calculations show that
the CO2 equivalent is only 0.4 percent of the CO2 emissions from combustion: N2O emissions have therefore been ignored in
the assessment of GHG impacts.
154
This calculation does not take into account the price elasticity of demand – a subject recently examined by the University
of Pretoria in connection with a proposed levy of 2 Rand Cents/kWh as a way of funding the REFIT (Reyno Seymore et al.
The impact of an electricity generation tax on the economy of South Africa, University of Pretoria Economics Department
Working paper, August 2009.) A 10 percent increase in electricity price was found to reduce total electricity demand by 10
percent, accompanied by a GDP contraction of 0.28 percent.
170
Box 1: The Social Cost of Carbon
The research on the social cost of carbon is large and growing; with a large range from a small net benefit to several hundred
dollars a ton. Thus, almost any estimate would find some support. Tol’s 2007 meta-analysis of the peer-reviewed literature,
which updated an earlier 2005 meta analysis, 155 cites 211 studies, with a mean of US$120/ton of Carbon (US$33/ton CO2 for
studies published in 1996-2001), and $88/ton of Carbon ($24/ton CO2 for studies published since 2001.156
The $29/ton CO2 used in this analysis of Medupi is based on the Stern Review, which states that “the mean value of the
estimates of the (2005) study by Tol was about $29/ton CO2 though the current social cost of carbon might be around $85/ton
CO2”
Even the $29/ton estimate has come under wide criticism, not least from Tol himself, who notes that the $29/ton figure was
cited out of context, for Tol concluded in the 2005 study that “it is unlikely that the marginal damage costs of emissions
exceeds $50/ton of Carbon (US$14 ton CO2) and are likely to be substantially lower than that”
31.
CO2 Emissions – Medupi v/s the GoSA’s DSM and REFIT Programs: The net GHG emissions
of Medupi must be placed in the context of the Government’s overall program to achieve a lowercarbon expansion path. Analysis was conducted to compare the net emissions of the DSM program,
the Renewable energy target under the REFIT program, and Medupi power project. To carry out a
conservative assessment, it is assumed that the 10,000 GWh RE target is reached four years later – in
2017 and that the Medupi is replacing gas-fired (LNG) generation. As shown in Table 3, CO2 emission
savings from the GoSA DSM program and the REFIT renewable energy program exceed the
incremental emissions from the Medupi Power Plant for life of the Coal-fired Power Plant.
Table 3: CO2 Emissions – Medupi Power Plant v/s GoSA REFIT & DSM Programs
DSM program
energy
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
(GWh)
[1]
428
662
1,156
3,058
5,291
7,140
8,782
10,477
12,172
13,867
15,562
Renewable energy program (REFIT)
avoided CO2
emissons
(mtpy)
[2]
0.4
0.7
1.2
3.1
5.4
7.4
9.0
10.8
12.5
14.3
16.0
energy
avoided CO2
emissions
(mtpy)
[4]
0.00
0.52
1.03
2.06
4.12
6.18
8.24
9.27
10.30
10.30
10.30
(GWh)
[3]
0
500
1,000
2,000
4,000
6,000
8,000
9,000
10,000
10,000
10,000
Medupi
total
[2]+[4]
(mtpy)
[5]
0.4
1.2
2.2
5.2
9.6
13.5
17.3
20.1
22.8
24.6
26.3
netCO2
emissions
(mtpy)
[6]
2.4
7.2
11.5
15.6
16.7
16.7
16.7
16.7
Net impact
[5]-[6]
netCO2
emissions
(mtpy)
[7]
0.4
1.2
2.2
2.8
2.4
2.0
1.7
3.3
6.1
7.9
9.6
32.
Incorporating GHG emission damage costs: When life cycle (non-combustion) GHG
emissions form Medupi are taken into account the ERR falls slightly. As discussed in the detailed
economic analysis report, life cycle emissions add 40.6 grams/kWh to the gross emissions of Medupi:
in consequence, the ERR decreases from 21.5% to 21.3% (see Table 4).
Table 4: Impact of Life-cycle Emissions on ERR
ERR
Baseline ERR
24.0%
adjusted for combustion GHG emissions at $28/ton CO2
21.5%
adjusted for life cycle emissions at $29/ton CO2
21.3%
155
R. Tol, “The marginal damage costs of carbon dioxide emissions: An Assessment of the Uncertainties,” Energy Policy, 33,
2064-2074.
156
R. Tol, “The social cost of carbon: trends, outliers and Catastrophes,” Economics e-Journal, 2008-25.
171
33.
However, there are some significant differences in carbon shadow prices when life-cycle
emissions are included, as shown in Table 5. Where the additional non-combustion emissions of
Medupi coal are greater than those of the alternative (e.g. for wind), the shadow price decreases; where
they are less than the alternative (as for LNG), the shadow price increases. Indeed, the biggest change
is for the LNG alternative, with an increase from 105$/ton CO2 to 135$/ton CO2.
Table 5: Impact of Life-cycle Emissions on Carbon Shadow prices, US$/ton of CO2
Combustion only
Life-cycle
Change
7
156
105
67
275
223
115
124
143
155
6
150
135
63
274
223
109
118
136
147
-1
-10
+30
-4
-1
0
-6
-6
-7
-7
Hydro(Inge-III)
CCCT(HFO)
CCGT-LNG
Nuclear
CCCT(gasoil)
UCG
CSP
Wind
CSP storage
CSP storage (Upington)
34.
Risk Assessment and Sensitivity/Scenario Analysis: The main risk factors for the Medupi
project are as follows:








Construction cost increases (whether due to cost overruns and construction problems, or an
escalation of costs due to increasing world commodity prices or to full order books of
equipment manufacturers).
Increases in the relative price of coal to oil (as might be the case if strong demand for coal in
the South African economy increases the local price to above the netback cost based on
international prices).
A decrease in the world oil price (which would decrease consumer’s willingness to pay which
is based on the cost of petroleum products for self generation, or for household use of kerosene
for lighting).
Less than expected demand for electricity (though Medupi will be one of Eskom’s most
efficient plants, lower electricity demand may cause it to be dispatched less than expected).
Lower than expected plant performance (lower heat rate than expected, higher O&M costs).
Shorter plant life than expected (currently at least 50 years, with several major refurbishments
planned at regular intervals).
Much higher opportunity cost of consumptive water use.
A higher carbon price than the $29/ton CO2 assumed in the baseline estimate.
35.
Each of these risk factors has been evaluated in a detailed sensitivity analysis, the results of
which are summarized in Table 6.
Table 6: Summary of Switching Values
Risk factor
Construction cost increase
World oil price (no change in Medupi coal
price)
Consumer WTP
Units
Baseline
Assumption
Switching
Value at
which NVP =
0
Assessment
of Risk
$/kW
2,203
6,131
very low
$US/bbl
75
17
very low
UScents/kWh
17.5
10
low
172
Risk factor
Value of Medupi coal
Lower than expected plant efficiency (net)
Average annual plant factor (first year)
Opportunity cost of water
Plant life
36.
Units
Baseline
Assumption
Switching
Value at
which NVP =
0
Assessment
of Risk
US$/ton
[%]
[%]
Rand/m3
years
31.9
37.5%
90%
20
50
155
0.08
39%
>200
5
extremely low
extremely low
extremely low
extremely low
extremely low
The main conclusions of the sensitivity analysis are as follows:

Opportunity cost of water: Water is a resource in critical supply in South Africa, and clearly
the present financial price (less than 1 Rand/1000 litres) does not reflect the opportunity cost.
Even the expected increase to 20 Rand/1000litres may not reflect the economic value. Even a
ten-fold increase in the economic value little affects the economic returns – which is the
reason Eskom’s decision to use dry cooling for its power stations is well regarded.

Plant life: The hurdle rate is achieved after five years of operation, and 20 percent return is
reached by 2022. Thereafter the returns increase only very slowly, and any extension of plant
life beyond 30 years has little further impact on the ERR.

Fuel (Coal) prices for the Power Plant: At constant world oil prices (and hence the level of
benefits constant), and allowing the Medupi coal price to vary, the switching value is
calculated at US$ 155/ton, which is 5 times the baseline value of US$ 31.9/ton. While such
very high coal prices were observed at the peak of the commodities boom in 2008, they were
accompanied by a corresponding increase in the world oil price, and hence in the consumer
WTP. This level of coal price in South Africa, without a corresponding surge in oil price (and
indeed of related fuels such as LNG, were the alternative to Medupi cast as LNG-fuelled
CCGT), is not expected.

Plant efficiency: Including the damage cost of carbon at the high estimate in the Stern Review
($ 85/tonCO2), the switching value of 15 percent plant efficiency is still low. Lower than
expected plant efficiency in no way threatens the economic returns, even at high valuations of
GHG damage costs.
37.
Sensitivity to the carbon price: When GHG damage costs are included in the analysis, the
sensitivity analysis of economic returns against the carbon price reveals the carbon shadow price at
US$ 142/ton, as shown in Figure 5. This is almost twice the higher estimate in the Stern Review of
$85/to CO2.
Figure 5: Sensitivity of Economic Returns of Medupi Power Project to Carbon Prices
173
38.
Scenario assessment: While the sensitivity analysis and switching values reveal the sensitivity
of individual assumptions on the economic returns, the robustness of the choice of the Medupi Power
Plant is further illustrated by a scenario analysis, in which alternatives to the baseline assumptions
above have been identified with the intent of examining combinations of outcomes that lead to both
more, and less favorable outcomes for the project investments. In the pessimistic scenario assumptions
have been made that tend to lower economic returns, to answer the question of whether the Medupi
coal project is still warranted under worst case conditions. Table 7 summarizes key assumptions for
each of the scenarios. The drivers of the two scenarios are as follows:

Optimistic scenario: robust global economic growth leading to increasing world oil and
commodity prices, and hence higher costs of coal (and also a higher WTP as oil prices
increase). Construction cost overruns are also likely in this scenario as equipment prices
increase in a seller’s market when order books are full, and steel and copper prices are
high.

Pessimistic scenario: lower economic growth, high damage costs to South Africa from
climate change leading to less than expected electricity demand growth, and increasing
water shortages. This is coupled with disappointing project performance – less than
expected efficiency, construction cost overruns.
Table 7: Assumptions for Scenario Analysis
Assumptions
Pessimistic
Scenrio
Units
Baseline
(High damage
costs of climate
change to South
Africa)
World Oil Price
Coal Price (fob Newcastle,
relative to world oil price on a
BTU basis)
Average willingness-to-pay
Plant efficiency (net)
Opportunity cost of consumptive
water use
Plant factor
(High World
Economic
Growth)
$/bbl
50
75
125
[]
.25
.25
.35
10% cost
overrun
baseline
15% cost
increase
$/ton
60
29
20
US cents/kWh
14.0
17.5
24.0
[]
0.35
0.375
0.375
Rand/m3
60
20
60
[%]
80% falling to
70%
90% falling to
80%
90% falling to
80%
Construction costs
Carbon price
Optimistic
Scenario
39.
When the world oil price surges, experience shows that not only does the coal price also rise;
its relative price rises as well. Thus, during the oil price boom of 2007-2008, the relative coal price
increased from its long-term average of about 25 percent of the oil price to over 35 percent.
40.
Average consumer willingness to pay is correlated with the world oil price: when that is low
($50/bbl), diesel oil prices also fall and hence the decrease from 17.5 US cents/kWh to 14 US
cents/kWh.
41.
Construction costs increase in both the pessimistic and optimistic cases. In the former case, the
increase would be attributable to project implementation problems and delays. In the optimistic case,
which hypothesizes a resumption of strong world economic growth over the next two decades, the
174
construction cost increase is attributable to escalating world steel (and commodity prices), and full
order books for global equipment manufacturers leading to a seller’s market for power generation
equipment (much as occurred in 2005-2007 prior to the global financial crisis).
42.
In the case of the opportunity cost of water, it is assumed that in a booming world and South
African economy, water demands will increase, and thus a tripling of the opportunity cost is assumed.
Such an increase is equally likely in a pessimistic scenario, where we hypothesizes high damage costs
from major climate change, which will doubtless include further pressure on water resources.
43.
Similarly, in the pessimistic scenario, electricity demand assumed to fall, with a lesser
probability of high levels of dispatch at Medupi.
44.
The results of this scenario analysis are shown in Table 8. As expected, the downside risk
exceeds the upside risk. However, even under the worst case scenario (low world oil price,
construction cost overruns, and low consumer willingness to pay), the ERR falls from 23.9 percent to
16.0 percent, and when higher GHG damages are included in the pessimistic case, the ERR falls to
10.6 percent; slightly above the 10 percent hurdle/discount rate.
Table 8: Medupi Power Plant: Economics – Scenario Analysis
Pessimistic
Baseline
Optimistic scenario
ERR
16.0%
24.0%
25.8%
ERR including GHG
damage costs
10.6%
21.5%
23.9%
45.
Based on the above analysis, it is concluded that Medupi Power plant is economically viable,
and has high economic returns and that the returns are robust to wide ranges of uncertainty in
assumptions. As explained above, the hydro and nuclear options are also part of Eskom’s expansion
plans, and are complements rather than substitutes for Medupi.
Costing Assumptions used in the Economic Assessment for the Medupi Power Plant and Alternatives
46.
The following summarizes the main assumptions for the baseline evaluation of Medupi:

Installed capacity: 6 x 795 MW gross, 6 x 764 MW net. Auxiliary consumption 3.9 percent.
Auxiliary consumption increases to 5.4 percent once the FGD units are in place, with
corresponding reduction in net output.

FGD system: Cost based on 150$/kW. First unit commences in mid 2008 and completed in 6
months: subsequent units at 6 monthly intervals.
Phasing of construction costs: Consistent with the phasing used in the financial analysis, 32
percent, 51 percent, 12 percent and 5 percent in 2010, 2011, 2012 and 2013, respectively.
Plant factor: The average plant factor in the Eskom fleet is 85 percent. The first year plant
factor is assumed at 90 percent, declining to 80 percent over the plant lifetime. As a
supercritical plant, Medupi will be at the top of the merit order, and likely to be dispatched to
the maximum availability.
Consumptive water use: With the FGD units in place, water consumption is 12 million m3 per
year.
Value of water: the present (financial) price is 30Randcents/ m3. The full cost of water once
the new scheme is completed is expected to rise to 20 Rand/m3, which is taken as the
economic cost for the entire planning horizon.




47.
Large Hydro (Inga III): The only hydro project conceivably of a scale to be considered as a
near-term alternative to Medupi is the 4,350 MW Inga III project in the DRC. This is a further
175
development of the hydro development of the lower Congo river: Inga I (351 MW, commissioned in
1972), and Inga II (1,424 MW, commissioned in 1983).157 The Inga III project has many variants,
particularly with regard to the allocation of its output to other countries in the region. Total project
costs have been estimated at $6.2 billion or $8.7 billion when financial costs and IDC are included. In
addition, extensive HVDC infrastructure will be required to bring power to South Africa. Several
proposed corridors have been proposed for this, the final choice being dependent upon the extent of
off-take by other countries en route.
48.
If one allocates costs to South Africa on the basis of gross MW, then its 2,350 MW share
would account for 57 percent of the generating plant cost, $3.5billion ($6.2billion x 0.57= $3.5
billion). WESTCOR’s158 share of the transmission system capital expenditure has been estimated at
$2.66 billion, so the total capital expenditure (before financial costs), allocable to South Africa, is
taken as $6.16 billion. Given the very long distances involved (3,000 km), transmission losses will be
high: the total expected overnight capital-cost/kW (net) is $3,277/kW.
49.
The annual capacity factor will be high because of the downstream location of Inga-III, with
large flows available even during the dry season. The annual energy estimated is 30,152GWh/year for
the 16 x 270 MW=4,320 MW variant, equivalent to 80 percent. Assuming WESTCOR’s share of
generation at 57 percent of the total, the net delivery at the Eskom connection point would be
13,749GWh/year, so on a net received basis (1,880 MW net) the annual plant factor is 83 percent. This
is less than 50 percent of the energy delivered by Medupi.
50.
Though the delivered cost appears competitive based on these assumptions, the uncertainties geopolitical, financial and technical - are formidable, and even under optimistic conditions the time
frame for significant power flows to be available to Eskom is 2022 at the earliest.
51.
Liquefied Natural Gas (LNG): Combined-cycle fuelled by LNG is the obvious fossil
generation alternative to Medupi coal, since it has both lower capital investment cost for power
generation, and lower GHG emission per net kWh due to its high thermal efficiency. However, there is
a significant capital investment cost associated with the required LNG terminal/regasification facility.
Of necessity, such an alternative would require a coastal location, since there are significant cost
penalties if the power plant is not adjacent to the regasification facility. A coastal location would also
avoid any costs of consumptive freshwater use for the steam cycle.
52.
LNG terminals are expensive, though the scale of LNG imports for a 5,160 MW project brings
the necessary throughput to exploit scale economies: at 75 percent load factor, the LNG project would
require imports of 4.86 million tons per annum (mtpa). While the costs of terminal and regasification
facilities has declined somewhat over the past decade, recent studies of LNG terminal costs for
Singapore (with an expected 2018 throughput of 6 mtpa) are in excess of $US1 billion.159 For 4.86
mtpa we assume a capital-cost of $900 million.
53.
The assumption for capital-cost of CCCT is 11,377 Rand/kW, or $1,422/kW (net) in Eskom
generation plan (ISEP 12) and the DoE’s IRP. This is somewhat higher than some other recent
estimates for CCGT in the Asia-Pacific area: the average of four recent estimates is $961/kW (gross,
ISO).160 At the expected average annual ambient operating temperature for South African coastal
157
There is also the possibility of a 43,000 MW “Grand Inga” project, but its realization is almost certainly not possible
before 2030, and faces even greater geopolitical hurdles (with a northern offtake to reach Cairo) than Inga-III.
158
WESTCOR is a joint venture that will build, own and operate the infrastructure of the western transmission corridor.
159
Singapore Energy Market Authority, Initial Findings and views on the import of LNG into Singapore, October 2005.
160
KEMA, LRMC of CCGT generation in Singapore for technical parameters used for setting the vesting price for the period
1 January 2009 – 31 December 2010, Report of the Energy Market Authority of Singapore, June 2009 estimates 969$/kW(n);
Vietnam: Institute of Energy, Hanoi, India for Non Trach 1 is 902$/kW(n), for Non Trach II, 1008/kW(n); URS, Study of
Equipment Prices in the Energy Sector, Report to the World Bank, 2008 estimates 1212$/kW(n).
176
locations of 200C, the capacity reduction relative to ISO conditions is only 2 percent, so assuming 4
percent auxiliary consumption, $961/kW (ISO) converts to $1,023/kW (net).
54.
CCCT using heavy fuel oil: CCCTs running on heavy fuel oil may be unusual, but with heavy
fuel oil costing significantly less than auto diesel,161 the fuel costs outweigh the operating-cost
penalties associated with the need to frequently wash the turbine blades. With a forced outage rate of 8
percent, the maximum availability is 76.6 percent. This alternative can be assumed to operate as a
baseload project with 75 percent annual load factor.
55.
Nuclear: The capital-cost assumptions of Eskom’s ISEP-12 study are between 4,966$/kw and
6,797$/kW (overnight costs), and $6,625-10,518/kW for completed financial cost. Such wide variation
in capital-cost estimates reflects similar ranges in the international literature. The 2009 update to the
MIT nuclear study162 estimates overnight costs at $4,000/kW, but when interest during construction
(IDC) is added, the cost increases to $5,600. Late 2008 cost estimates for US utilities are $4,924/kW
(Duke Energy, overnight) to TVA Bellafonte ($7,833/kW, including financial costs).163 Reported costs
for Chinese nuclear plants are much lower, in the range of $1,400-1,800/kW for overnight costs for the
nuclear EPC (i.e. without site costs, cooling system etc).
56.
No less uncertain are the costs of design concepts (small unit size reactors in the 250-500 MW
size range, advanced breeder reactors, etc.) under development in many countries, but none of which
are yet commercially available. The track record of capital-cost overruns in the nuclear industry is very
poor, in part because of lengthy construction delays (notably in the US).
57.
Wind: Wind sites have been categorized by DME into 7 classes,164 with wind speeds ranging
from 5.5-6.0 m/s (class 7), with load factors of 17 percent, to Class 1 sites with average annual wind
speeds in excess of 8.5 m/s and estimated achievable load factors of 38 percent (Table 9). However,
although the resource potential is large (in excess of 64,000 GWh), none are financially feasible
without additional financial support,165 and even the Class 1 wind sites only enter into the aggregate
supply curve in the last 1,000 GWh of the 10,000 GWh total renewable energy target set for REMT.
Table 9: Wind Power Survey Results
Class 1
Class 2
Class 3
Class 4
Class 5
Class 6
Class 7
Wind speed
(m/s)
Expected
Annual Load
Factor
GWh
R/kWh
MW
>8.5
8.0-8.5
7.5-8.0
7.0-7.5
6.5-7.0
6.0-6.5
5.5-6.0
0.37
0.35
0.31
0.27
0.24
0.2
0.17
63
78
167
5,109
24,841
31,139
2,705
0.38
0.40
0.45
0.51
0.58
0.70
0.82
19
25
61
2,160
11,816
17,773
1,816
Total
64,102
Source: REMT, op.cit. Table 4.19
58.
In order to produce the same annual net energy as Medupi, 32,676 GWh (at an 85 percent
annual average load factor) most of the available energy would be in class 5 sites, where load factors
are 24 percent: with 0.5 percent own use, the wind farm would need to produce gross energy of
161
At 75$/bbl for crude oil, HFO is 60$/bbl, while auto diesel (gasoil) is $90/bbl.
MIT, 2009 Update of the 2003 Report Future of Nuclear Power, Cambridge, Mass., 2009
163
World Nuclear Association, The Economics of Nuclear Power, November 2008.
164
Department of Minerals and Energy, 2002. White Paper on the Promotion of Renewable Energy and Clean Energy
Development.
165
On March 31 2009, South Africa introduced a feed-in tariff for wind projects, 1.25 Rand/kWh, or 15.6UScents /kWh.
162
177
32,840GWh, requiring an installed capacity of 15,310 MW at an average annual load factor of 24.5
percent
59.
According to the 2008 annual survey in Wind Power Monthly, in 2008 the average investment
cost for wind projects was 1300-1700 Euro/kW.166 The average equipment price is reported as 1100
Euro/kW, and balance of project costs are 200-600 Euro/kW. Assuming South African site costs at 300
Euro/kW, capital-costs are taken as 1400Euro/kW, or $2,030/kW. Assuming own use of 0.5percent,
the (overnight) capital-cost is $2,050/kW (net).
60.
A major issue for wind projects is the extent to which they generate capacity benefits. Being
non-dispatchable, and with extended periods when wind speeds are below minimum cut-in speeds,
wind must be supplemented with standby capacity to cover these intervals in order to be considered
equivalent to a fossil-fueled baseload plant. If one sets the capacity credit equal to the annual load
factor (divided by the annual load factor of dispatchable baseload plants), a 1,000 MW wind farm at
the 24 percent annual load factor has a capacity credit of about 320 MW, implying that an additional
680 MW of open cycle combustion turbine capacity must be available to the system. This technology
has the lowest cost per MW, and is generally used as a proxy for the pure cost of capacity. Therefore,
assuming an OCCT cost of $500/kW, every kW of wind capacity requires a further 0.68 KW of open
cycle capacity, or 0.68 x 500 = $340/kW, for a total capacity cost of wind power of $2,370/kW.
61.
Concentrating solar power (CSP): The Northern Cape area of South Africa (together with
neighbouring areas in Namibia and Botswana) has one of the highest solar energy potentials in the
world: the Uppington CSP site has radiation levels equivalent to 8.17kWh/m2/day (2,980kWh
/m2/year). By way of comparison, North Africa has potential of 1,825-2,550 kWh/m2/day, and the
White river valley, Nevada (USA) 2,300-2,700 kWh/m2/year.
62.
Reliable cost estimates for CSP are scarce, and span wide ranges of costs and capacity factor
assumptions. The Bank’s Clean Technology Fund concept note for CSP scale up in North Africa
estimates capital-costs between $4,000 and $6,000 per kW for a typical capacity factor of 22-24
percent (without storage),167,168 An earlier ESMAP assessment (with costs at 2004 price levels)
estimates a 54 percent capacity factor for CSP with storage at $4,780/kW, or $2,450/kW for a 20
percent capacity factor without storage; in other words the addition of storage doubles the capitalcost.169 Eskom and DoE IRP overnight capital-cost estimate for a 1,000 MW CSP is Rand 51,731/kW,
or $6,466/kW, with an estimated capacity factor of 60 percent (46-73 percent); the 100 MW(e)
Upington CSP project will use molten salt storage and costs US$600 million, or 6000$/kW (excluding
contingencies). The widely cited study by Ummel and Wheeler assumes a 250 MW CSP with no
storage (and a capacity factor of 26 percent) to cost $2,924-3,096/kW, and $5,388-5,704/kW for CSP
with storage to achieve a capacity factor of 60 percent.170
63.
The ability to store energy is critical to the economics of CSP, and with typical 6 hour storage,
the CSP becomes equivalent to a daily cycling plant running for 12-14 hours a day. This configuration
with 6-hour storage is the basis for a number of proposed CSP projects in North America, based on
166
Wind power Monthly, January 2009, pp 51-55.
Clean Technology Fund, Concept note for a Concentrating Solar Power Scale-up Program in the Middle East and North
Africa Region, 27 April 2009 (CTF/ TFC 3/7).
168
Botswana: Morupule B Generation and Transmission Project, Project Appraisal Document, 49183-BW, dated October 2,
2009.
169
ESMAP, Technical and Economic Assessment: Off Grid, Mini-Grid and Grid Electrification Technologies, Summary
Report, November 2005: Table 5.1
170
K. Ummel and D. Wheeler, Desert Power: the Economics of Solar Thermal Electricity for Europe, North Africa and the
Middle East, Working Paper 16, Centre for Global Development, Washington, DC., 2008.
167
178
work at the US National Renewable Energy Laboratory (NREL) and the California Public Utilities
Commission.171
64.
While Eskom’s capital-cost estimate is not unreasonable for a CSP of such a high capacity
factor, whether such high capacity factors can actually be achieved is still unclear in light of the lack of
actual commercial operating experience of such a technology. Consequently we assess three CSP
variants:

Eskom assumptions ($6,466/kW). These assumptions are based on a full scale 1000 MW
commercial CSP project as examined in Eskom’s ISEP-12 studies.

Assumptions in the US literature based on the various studies by NREL and US West
Coast utility commissions; 6-hour storage; costs as estimated for the Nevada White River
Valley scheme for a 2015 commissioning.($4,100/kW)

No storage, 26 percent capacity factor, with a capital-cost ratio to the storage project as in
Ummel and Wheeler (55 percent).($2225/kW)
65.
Underground Coal gasification: The extent to which underground coal gasification (UCG) can
be viewed as a realistic alternative to Medupi is doubtful. In January 2007 Eskom commissioned a 6
MW pilot plant (using open cycle gas turbines), which is to be followed by a 40 MW demonstration
plant and then a 2100 MW commercial scale project.
66.
There are several advantages to this technology: GHG emissions are expected to be some 25
percent lower than conventional coal combustion, and there is no requirement for waste disposal. Most
importantly, this permits utilization of coal resources that are not economically extractable – low
quality, deep depths of 300-600m, and in thin fragmented seams. Consequently in the economic
analysis, the opportunity cost of this coal resource is zero: the fuel costs are simply those involved in
gasification. Eskom’s ISEP-12 assumptions for UCG estimate an overnight capital-cost of $1,777/kW.
Component B – Renewable Energy Projects – Sere Wind Power Project and Upington CSP
67.
Economic Rationale: The catalytic role of the proposed renewable projects is the driving force
behind development of the proposed Sere Wind and Upington CSP projects. Assessing these projects
as a source of incremental power alone would fail to capture the full benefits of these investments. The
wind and concentrating solar power (CSP) projects are being developed primarily to help deliver on
South Africa’s commitment to follow mitigation strategies set out in the Long-Term Mitigation
Scenarios (LTMS). Under the LTMS, South Africa will start to reduce growth in emissions
immediately and will reduce gross emissions from 2030 onwards.
68.
The two projects – as a first of their kind - are seen as a test case and catalyst for larger scale
delivery of power using these technologies to displace considerable future CO2 emissions (and
generate economic externality benefits in the process) and are very much in response to the need to
support the Government in operationalizing its plans under the LTMS. The Government’s strategy on
mitigation requires such projects to be developed, and assessment of economic viability of each of
these projects should therefore take account of their broader role in making future economically
attractive projects take place earlier and in greater numbers. By putting in place a set of feed-in tariffs
171
See e.g., California Public Utilities Commission, New Concentrating Solar Power (CSP) Generation Resource, Cost, and
Performance Assumptions, October 2007.
179
specific to these technologies172, the Government has acknowledged the importance of each of these
technologies to South Africa’s future commitments on low carbon growth.
69.
South Africa has very little established wind power and the wind project would play an
important role in facilitating increased future investment in the sector. A full assessment of the
economic viability of the Sere Wind Power Project would take account of the knock-on benefits of this
project for future projects. The project will include investment in transmission which will reduce costs
for future projects. In terms of reducing risks, the project will test out the institutional/regulatory
conditions and will help reduce uncertainty with borrowing terms relating to bankable power purchase
agreements and the operation of the Renewable Energy Feed-in Tariff. The project will also provide
greater certainty on equipment and operating-costs in the South African context. If the various cost and
risk barriers can be reduced through this project, the consensus view is that there is potential for some
4 GW of wind power in South Africa which would form an important part of South Africa meeting its
commitments set out under the LTMS. In addition, certainty around project costs and a track-record of
operational wind power in the country will provide comfort to the private sector, thus paving the way
for a successful PPP program for renewable energy in South Africa under the GoSA’s REFIT
program.
70.
For CSP, the broader knock-on impacts of this project are critical to South Africa’s ability to
follow the path set out by the LTMS. The LTMS finds CSP to be a realistic alternative to coal power
plants for baseload capacity. CSP with thermal storage (as envisaged for this project) is one of the few
renewable supply options that can provide baseload and dispatchable power. Currently, almost all the
power requirements for Eskom are provided by large coal-fired power stations. Eskom has estimated
that there are resources for about 40 GW of solar thermal power in the Northern Cape and Western
Cape provinces alone. The combination of potential scale and potential for replicating coal-fired power
generation’s dispatch ability in the system makes CSP the critical renewable energy technology for
enabling South Africa to meaningfully reduce absolute emissions by 2030 as per its commitments.
Envisaged installed capacity of CSP by 2050 as set out in the LTMS indicates strong expectation that
CSP will be taken up in line with the full estimated resource size.
71.
The Upington CSP project also has considerable global significance in terms of its learning
effects. Southern Africa is one of a select number of regions around the world that is particularly
suited to CSP use. CSP has not been built and operated at large scale to date and this would be the
largest commercial CSP plant of its design in operation. First movers such as this project are expected
to provide considerable learning for future projects in South Africa and around the world. According
to the International Institute for Applied Systems Analysis, every time the total installed capacity for a
given technology doubles, the costs fall by about 10-15 percent on account of learning and economies
of scale. This suggests that to become competitive with fossil fuels, CSP would have to grow to be
about half the capacity of what wind is now173. The IEA finds a similar learning rate174 for CSP of 12
percent i.e. a 12 percent drop in prices every time there is a doubling of installed capacity. These initial
projects are therefore expected to have critically important impact on lowering costs of follow-on
plants. Given the scale of the long-term potential for CSP globally, this is a significant benefit from the
project that is impossible to quantify.
72.
Project Selection: For each technology, wind and CSP, the sites and configurations were
chosen in accordance with pursuing the least cost option for a given size and type of project.
172
We note that the wind feed-in tariff, at ZAR 1.25/kWh is set close to the assessment of the overall weighted average
consumer WTP for power in South Africa (US cent 17.5/kWh or ZAR 1.31/kWh). The feed-in tariff for CSP is considerably
higher at ZAR 2.10/kWh (US cent 28.0/kWh).
173
IIASA Policy Brief: Expanding solar energy in North Africa to achieve climate targets, #7, December 2009.
174
The speed at which costs fall in response to engineering, construction, and operational experience, improved material
procurement, and manufacturing scale is described by the learning rate.
180

For wind, the Western Sere Facility is fully scoped and specified. Importantly, as well as being
a “moderate” wind resource, the site is near a 132 kV sub-transmission line with sufficient
capacity to evacuate the power.

A number of solar technology alternatives and sites were assessed before a Concentrating
Solar Power project using power tower technology was chosen to be sited in Upington in the
Northern Cape. This included technical feasibility in choosing the site. The Upington site is
found to have one of the highest solar potential values in the world. The variety of technology
options was evaluated. Annual simulation models were run. Pilot plant designs were
developed and optimized to provide the lowest levelized energy cost for the location. The
results of the comprehensive assessment found the most promising option for the near term to
be a molten salt-type central receiver technology to be located in Upington. Full details of this
assessment can be found in the Eskom Environmental Impact Assessment175 stored in the
Project File.
73.
Economic Rate of Return and Sensitivity Analysis: The results of the economic analysis using
specific data available for the individual project and treating the project as a source of incremental
clean power alone shows that the Sere Wind Power Project has an ERR of 14.1 percent and an NPV of
$54.0m assuming an annual load factor of 25 percent and including the benefits of displaced CO2
emissions. Therefore, even without consideration of catalytic benefits due to this project, it is found to
be economically viable.
74.
Even though it is intended to design the plant for a load factor of 60-65 percent, because of the
limited long-term experience with the technology, the economic analysis is based on a conservative
load factor of 40 percent. Using specific data available for the individual project and treating the
project as a source of incremental clean power alone, the CSP project has an ERR of 4.0 percent and
an NPV of -$205.8 million assuming an annual load factor of 40 percent and including the benefits of
CO2 emissions. The proposed design of the CSP may allow the plant to achieve an annual load factor
of at least 60 percent and at this higher level, the ERR increases to 9.0 percent and the ENPV to -$37.0
million. South Africa does not have “green” tariffs and therefore it is impossible to directly observe
consumer willingness-to-pay for power from these technologies. It can be expected, though, that
Government policy seeks to reflect longer term population preferences. On this basis, if the feed-in
tariff for CSP (about USc 28.0/kWh) were taken as a proxy for higher national willingness-to-pay for
power from initial CSP projects (for the reasons linked to South Africa’s low carbon growth
aspirations described earlier), then the project ERR at 40 percent load factor would rise to 9.6 percent
and ENPV to US$ 15.2 million. For a CSP project with 60 percent load factor, the ERR would rise to
15.7 percent and ENPV to US$ 248.9 million.
75.
The table below summarizes the results of the sensitivity analysis. This shows that the
economic returns are strongly dependent on the annual load factor achieved by the plant. Also, that
returns are much more sensitive to capital-cost overruns during construction than they are to project
delays.
175
Vol 2. (Proposed Establishment of a Concentrating Solar Power Plant and Related Infrastructure in the Northern Cape
Province).
181
Table 10: Renewable projects - sensitivity analysis
Sere Wind Power Project (including benefits due to displacement of CO2)
EIRR
Load factor
ENPV (in
US$
millions)
ENPV (in
US$
millions)
EIRR
20%
ENPV (in
US$
millions)
EIRR
25%
32%
[email protected]/kWh
10.3%
+3.8m
14.1%
+54.0m
18.9%
+124.1m
Capital cost overrun by 10%
9.0%
-13.3m
12.6%
+36.8m
17.1%
+107.0m
Capital cost overrun by 20%
7.9%
-30.5m
11.3%
+19.7m
15.6%
+89.8m
1 year delay in entire project
9.8%
-1.9m
13.2%
+39.9m
17.7%
+107.4m
2 year delay in entire project
9.4%
-7.2m
12.2%
+27.2m
16.6%
+92.3m
Upington Concentrating Solar Power Project (including benefits due to displacement of CO2)
EIRR
Load factor
ENPV (in
US$
millions)
ENPV (in
US$
millions)
EIRR
40%
ENPV (in
US$
millions)
EIRR
60%
68%
WTP @28.0USc/kWh
9.6%
-15.8m
15.7%
+248.9m
17.8%
+355.7m
[email protected]/kWh
4.0%
-205.8m
9.0%
-37.0m
10.8%
+31.2m
Capital cost overrun by 10%
3.1%
-256.0m
7.9%
-87.2m
9.6%
-19.0m
Capital cost overrun by 20%
2.2%
6.9%
-137.4m
8.5%
-69.2m
1 year delay in entire project
3.9%
-203.0m
8.7%
-49.5m
10.3%
12.5m
2 year delay in entire project
3.8%
-200.4m
8.3%
-60.9m
9.9%
-4.5m
-306.2m
76.
Assumptions: The economic analysis is based on the following assumptions for both projects:
(a) cumulative losses between generation and consumption point are estimated at 10 percent; (b) the
total cost of transmission and distribution is US cents 2/kWh; (c) overall consumer willingness-to-pay
for power in South Africa is assessed at US cents 17.5/kWh (as discussed in more detail in Paragraph
155); and (d) displacement of CO2 per kWh of energy generated by CSP or wind is 1.03 kgs of
CO2/kWh (based on the Eskom emission grid factor published in the Eskom Annual Report 2009).
Specific project related assumptions for the proposed renewable energy projects are as follows:

Sere Wind Power Project - Assumptions: Total cost of project including transmission but
excluding IDC, taxes and import duties is based on overnight capital-cost of
US$2,050/kW(net); construction period is 3 years 2011-14 inclusive though some capital-costs
are incurred in a fourth year; power generation is assumed to begin during 2013; capital-costs
are incurred according to the following distribution: 32 percent in year 1, 51 percent in year 2,
12 percent in year 3 and 5 percent in year 4; extra capital-costs relating to transmission is $7
million; energy for own use is assumed at 1 percent of gross generation; operating and
maintenance fixed costs are assumed to be 1.26 percent of capital-costs; costs are assumed to
increase by 1 percent (real) per year; installed capacity is 100 MW; average hours of operation
per day are assumed to be 6 (25 percent load factor) for base case (sensitivities are assessed for
20 percent and 32 percent load factors); and plant operating life is assumed to be 20 years.

Upington CSP – Assumptions: Total cost of project including transmission but excluding IDC,
taxes and import duties is US$ 600 million (excluding any contingencies as well); construction
period is 3 years 2011-13 inclusive although minor amounts of capital-costs are incurred in a
fourth year; power generation is assumed to begin during 2013; capital-costs are incurred
according to the following distribution: 32 percent in year 1, 51 percent in year 2, 12 percent
in year 3 and 5 percent in year 4; energy for own use is assumed at 10 percent of gross
182
generation; operating and maintenance fixed costs are assumed to be 1 percent of capital-costs
and are assumed to increase at a real rate of 1 percent per year; installed capacity is 100 MWe;
average hours of operation per day are assumed to be 9.6 (load factor 40 percent) in the base
case with additional assessment for load factors of 60 percent and 68 percent; and plant
operating life is assumed to be 20 years.
Component C.1 – Majuba Rail Project
77.
Economic Rationale: The railway line under consideration is a new 69 km route from a start
point west of Ermelo (i.e., the start of the coal export line between the Witbank coal field and Richards
Bay) and the Majuba power station. The construction of the new rail line will provide sufficient line
capacity for the entire burn (estimated at around 13 MTpa for the medium-term) of the power station
to be transported by rail. The trains will be considerably larger than via the existing rail route as they
will be able to take advantage of the higher axle-load (26 versus 20 tons on the rest of the mainline
network) which, combined with the shorter rail distances, will reduce rail operating-costs by nearly 75
percent compared to existing rail operations. Heavy-haul unit rail operating-costs are also about 80
percent cheaper than the comparable unit road haulage costs.
78.
The traffic forecast for the Ermelo – Majuba line assumes that all the coal burnt by Majuba is
carried on the new line. Coal burnt in the future is expected to be of slightly better quality than at
present. The total burn is thus expected to decrease to 13 million tons, as against the 14 million tons
consumed at present. Majuba is a very efficient coal-fired station but its location means that it is
currently one of Eskom’s higher-cost stations due to the cost of transporting the coal from the mines.
Nevertheless, because of the current shortage of generating capacity in South Africa, 85 percent of the
Majuba generating capacity is currently being used and Majuba is designated to remain a baseload
station for at least the medium-term. This role will be strengthened by the construction of the new rail
line which will reduce substantially the coal transport cost (by R60 to 100 per ton depending on the
origin). In the longer-term, the new generation of power stations currently being planned will come onstream and Majuba is expected to gradually slip down Eskom’s power plants merit order, with a
corresponding reduction in its generation capacity usage rate (plant factor). The economic evaluation
assumes that Majuba will operate at a load factor of 65 percent by the end of the evaluation period
(2043/44), with the annual coal burn reducing to 10 MTpa.
79.
Little or no general freight is expected on the new line, which will be formally classified as a
private siding belonging to Eskom on which Transnet operate under contract. Table 11 summarizes the
2014/15 flows assumed in the analysis for both the ‘Without-project’ and ‘With-project’ cases. These
have been assumed to decline pro rata to an annual total of 10 MTpa by the end of the economic
impact evaluation period in 2043/44176.
Table 11: Forecast Coal Flows (MTpa) in 2014/15
Mine
Groengoeverden
Leeuwpan
Koornfontein
Uitkyk
Elders
Total
W/o Project
Existing Rail
2.880
0.600
0.600
3.600
7.680
Road
1.800
3.600
5.400
With Project
New Rail
2.880
0.600
1.800
0.600
7.200
13.080
80.
Project Costs: The estimated cost of the project infrastructure is R2.986 billion ($US398
million) at 2009 prices, excluding value added taxes of which about R189 million has already been
176
Majuba should still have 10 years of operational life remaining at that stage.
183
spent by Eskom. This sum is treated as sunk cost for the purposes of the economic analysis and thus
only R2.797 billion (US$ 373 million) is considered for calculation purposes. Likewise, in the
economic analysis, all input costs are assumed to be adjusted to market prices and no shadow price
factors have been used.
81.
There is no project-specific investment in rollingstock; the trains will be operated by TFR
using its own rolling stock.177 Accordingly, the cost of the rolling stock has been included in the train
operating-costs. An allowance of R160 million has been included in the economic evaluation to cover
investment required by TFR to provide sufficient capacity for the additional traffic in the feeder
network.
82.
Project Benefits: The benefits of the new construction of the line fall into three main
categories: (a) Operating Cost Savings; (b) Freeing up capacity in the Welgedag area; and (c) Wider
economic, social and environmental benefits.
83.
Operating cost savings: The project will result in a major reduction in operating-cost savings
for the traffic diverted to the new line, both for the traffic previously carried by conventional rail
(which will have the benefit of the more efficient heavy-haul operations combined with a much shorter
distance) and for traffic previously carried by truck (which will be carried by rail at around 20 to 25
percent of the actual road cost). These benefits have been derived from the estimated rail and road
operating-costs from each mine to Majuba, with and without the project.
84.
Within TFR, there are three main groups of traffic: (a) the export coal movements, mostly
from the Witbank area, through Ermelo to Richards Bay (32 percent of the total traffic); (b) the export
iron ore movements from Sishen to Saldanha in the Northern Cape (29 percent of the total traffic); and
(c) general freight movements over the rest of the network (39 percent of the total traffic). These three
groups have quite different operating characteristics and unit operating-costs which is reflected in their
average tariffs (in 2009 which ranged from R0.05/ntkm for the export iron ore through R0.12/ntkm for
the export coal to R0.28/ntkm for the general freight). The export coal and iron ore movements are
generally considered to cover their costs, whilst the general freight business is loss-making. As the
project involves coal movements migrating from the general freight operations to operations similar to
the export coal, separate operating-cost estimates were developed for each of the three groups of
operations.178 Aggregate costs were then estimated for each of the three freight transport groups,
together with unit costs (e.g. locomotive maintenance costs per loco-kilometer). Rolling stock capitalcosts were derived using replacement costs and typical utilization rates for electrified coal rail lines.
85.
These estimates were then used to estimate TFR’s operating-costs for: (i) the current coal
movements to Majuba operated by conventional 20 ton axle-load freight services (these trains are
block trains which are about 25 percent more technically efficient than the typical general freight
train); and (ii) the proposed coal movements using heavy-haul trains (with heavier axle loads of 26
versus 20 tons, larger wagons with 80 versus 60 tons carrying capacity, longer trains with 100 wagons
compared to 58 and more streamlined operations) when the project line is opened.
86.
In both cases the costing assumed that rail achieves a real productivity increase of 1 percent
p.a. throughout the evaluation period. Electricity prices were also assumed to increase by 50 percent in
real terms by 2014/15 but to remain constant thereafter. The end result was a reduction in the unit cost
of coal haulage (excluding the fixed component of rail infrastructure and any return on investment)
from R0.26/ntkm today on a general freight service to R0.11/ntkm for heavy coal service. In addition,
the new line will save an average of about 180 kilometers in transport distances to Majuba compared
177
It is estimated that TFR will require around 18 locomotives and up to 350 wagons to operate the service. These will be
drawn from TFR’s pool of rolling stock serving the export coal movements.
178
This was done by analyzing TFR published 2008 accounts, together with estimates of the physical resources (locomotivekm, wagon-km, gross tonne-kilometers etc.) required by each of the three groups as well as by holding direct talks with TFR
management.
184
to the current circuitous rail routing. This will translate into a further decline in the cost of supplying
the plant with coal which will reach in 2014 R20/ton versus R93/ton (again excluding the fixed cost of
infrastructure and any return on investment).
87.
The new distance by rail will average about 40 kilometers longer than the comparable road
distance but this is more than compensated for by the much lower unit operating-costs on rail. Eskom
currently has a large number of road coal transport contracts which are based on the reported average
costs of the South African Road Transport Association. These were analyzed for the routes serving
Majuba and adjusted to economic costs by eliminating insurance (as accidents are dealt with directly in
the evaluation) and the fuel duty and accident fund component of the cost of diesel (approximately 22
percent of the total fuel price). No allowance was made in the base evaluation for the shadow price of
labour, as there is a flourishing road transport sector and the number of drivers involved (about 1,500
is very small compared to total employment in the sector (in excess of 700,000). This potential
negative economic externality of road to rail transfer was instead addressed as a sensitivity test.
88.
The road usage-related costs were cross-checked against those used by South Africa National
Road Agency (SANRAL) for its highway evaluation procedures, using route-specific road
characteristics (roughness, grade etc). The resulting economic road operating-costs averaged R78/ton.
In the medium-term, road operating-costs associated with Majuba transport services are likely to
decrease as more efficient vehicles are introduced, roads are repaired and upgraded and management
practices among road haulage companies are improved. The 2014/15 vehicle operating-costs have
been assumed to be 85 percent of their current level and to decline by 1 percent in real terms
afterwards.
89.
The operating-cost savings for traffic which would otherwise travel by existing road and rail
routes were then derived by comparison with the future rail operating-costs once the Majuba line
becomes operational in 2014.
90.
Freeing-up capacity: Transferring the Majuba coal operations to the new line will provide
additional capacity for rail freight services in the Welgedag area. One development is likely to be that
the Tutuka power station, North of Majuba, can be supplied by rail instead of by road (as it is at
present) until 2018/19, when a new direct rail route to Tutuka will be in place. The rail capacity will
then be available to other general freight traffic. Given the uncertainties associated with these longterm developments and many external factors impacting these developments, and to be conservative in
the assessment, no explicit benefit for either of these possibilities has been included in the economic
evaluation.
91.
Wider economic and environmental benefits: The external benefits included in the economic
impact analysis include a reduction in road accidents and congestion, reductions in road maintenance
costs and changes in greenhouse gases (GHG). The reduction in road accidents has been estimated
using statistics on the number of accidents associated with the coal transport fleet, converted into a rate
per vehicle-kilometer. These have been converted into monetary equivalents using the standard values
used in highway evaluations in South Africa as provided by SANRAL.
92.
Coal trucks represent a large proportion of the total traffic on some routes and the transfer of
coal transport to rail will improve travelling conditions for the non-coal traffic. The reduction in traffic
delays has also been estimated by estimating the change in the volume/capacity ratio on these roads,
following the transfer of the coal traffic, and the consequent change in average travel speed. These
have been cross-checked against detailed information held by SANRAL. Many of the roads used by
the coal trucks are essentially rural farm-to-market roads, constructed with relatively thin structures
and which have already suffered severe damage from coal traffic. In the absence of any transfer to rail,
such damage will be experienced on a continuing basis and this has been estimated from damagerelated road maintenance costs provided by SANRAL.
185
93.
Greenhouse gas benefits were estimated from unit fuel and energy consumptions of road and
rail transport. Rail energy consumptions were derived from data provided by TFR and road diesel fuel
consumptions from the road cost analysis supplemented by SANRAL. These were then converted into
unit emissions of carbon dioxide. In the case of electricity, emission levels were converted using
Eskom production system average of 0.97 g/kwh, with an allowance of 7 percent for power
transmission losses. Diesel fuel was converted using the standard value of 2.63 kg/liter of CO2 per liter
of Diesel fuel. The difference in carbon dioxide emissions from each transport option was then
converted into monetary equivalent using a unit economic cost of US$29/ton of CO2, as used in the
parallel evaluations.
94.
Economic Rate of Return and Sensitivity Analysis: Assuming a project life of 30 years, the
project is expected to have an Economic Internal Rate of Return (EIRR) of 18.7 percent and a Net
Present Value (NPV) of R3.28 billion (US$ 437 million) in 2009 prices (at a discount rate of 10
percent). Table 12 provides an overview of project cost and benefits.
Table 12: Analysis of Project Benefits (in Rand Millions; discounted to 2014/15)
Rail Operating Costs
Road Operating costs
3,601
52
2,191
32
Total Benefits
Share of all benefits (%)
Construction costs
External
benefits
1,095
16
NPV
Total
6,887
100
-3,605
3,282
95.
The sensitivity of these results was tested against changes in a range of base case assumptions
including: an increase in investment costs of 50 percent; only rail and road operating-cost savings;
leaving 50 percent of the rail traffic on the existing route; excluding cost savings associated with truck
labour; and Greenhouse gases valued at US$10 per tonne of carbon dioxide. The results of these tests
are given in Table 13.
Table 13: Majuba Rail Project - Sensitivity Analysis
EIRR
(as a %)
Sensitivity
Base Case
Construction costs +50 percent
Include rail and road operating savings only
50% of rail traffic travels by current route
Excluding truck labour cost savings
Greenhouse gases valued at $10 per tonne
19
13
16
14
18
18
ENPV
(in Rand Millions)
3,282
1,479
2,187
1,427
2,480
3,152
96.
As shown above, the project EIRR is found to be robust against all sensitivity tests and even if
the analysis is restricted to benefits from the operating-cost savings, discounting all external benefits
associated with the road traffic, the EIRR is still 16 percent.
Project Economics as a Whole
97.
Table 14 below summarizes the results of the economic analysis carried out for the project.
The baseline aggregate project economic return is 22.7 percent, with an NPV of US$ 15,439 million.
The benefits of the project are assessed as the consumer’s willingness to pay (WTP) for the
incremental power produced by the project, with an average benefit of 17.5 US cents/kWh.
186
Table 14: Project Economics as a Whole
Component
ERR
(as a %)
24.0%
10.7%
1.8%
19.0%
22.7%
A - Medupi Coal
B - Wind
B - CSP
C - Majuba Railway
Project as a Whole
NPV @ 10%
US$ Millions
15,727
9.2
-266
437
15,907
98.
As shown in Table 15, when the changes in GHG emissions are taken into account, and based
on a carbon valuation of US$ 29/ton of CO2, the economic returns of the project decrease. As
expected, the bulk of the impact is attributable to the Medupi coal project, whose returns are
negatively affected as it is the only carbon emitting project. The economic returns of the wind, CSP,
and Majuba Railway project components all increase slightly.
Table 15: Project Economics as a Whole, including CO2 valued at US$29/ton
A - Medupi Coal
B - Wind
B - CSP
C - Majuba Railway
Project as a Whole
ERR (w/o
GHG)
ERR (w/ GHG)
Change in
EIRR
ENPV
(as a %)
24.0%
10.7%
1.8%
19.0%
22.7%
(as a %)
21.5%
14.1%
4.0%
19.6%
20.5%
(as a %)
-2.5%
3.4%
2.2%
0.6%
-2.2%
US$ Millions
12,585
54
-206
457
12,890
187
Annex 10: Financial Analysis
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Historical Financial Performance of Eskom
Electricity Sales
1.
Significant growth of the South African economy during the past few decades resulted in
corresponding increase in electricity consumption — From 1994 to 2008 Eskom's electricity sales
increased by more than 50 percent and reached 224 TWh in FY08 (ending March 31, 2008).
However, the outbreak of the global financial crisis in the second half of 2008 caused South
Africa’s economy to fall into recession. Thus for FY09, Eskom’s electricity sales decreased by 4
percent to 215 TWh, mainly because of the reduction in electricity demand from the steel
industry, mines and smelters.
2.
At the same time, the revenue realized from electricity sales increased by 22 percent from
R43.5 billion in FY08 to R53.0 billion in FY09 due to 27.5 percent average tariff increase
approved by NERSA in June 2008. The unit average price of electricity increased from 19.59
Rc/kWh in FY08 to 24.97 Rc/kWh in FY09. The 27.5 percent tariff increase approved by
NERSA in FY09 was significantly higher than 5-6 percent tariff growth rate in FY05-FY08 and
was a result of a sharp increase in primary energy costs (mostly coal) and accelerated capital
expenditures program initiated by Eskom in response to the to a series of electricity outages and
load shedding in 2007-2008 (for details on tariff structure see discussion on tariffs below and in
Annex 1).
3.
Redistributors, industrial and mining are the major customer segments for Eskom. Sales
to these three customer types constitute around 82 percent of the total sales of Eskom and account
for around 75 percent of the revenues. Export of electricity accounts for approximately 4 percent
of Eskom’s sales revenues. Eskom has long-term bilateral contracts to sell power to utilities and
companies in Mozambique, Lesotho, Namibia and Swaziland. A summary of the Eskom’s
electricity sales details during the past three years is presented in Table 1 below.
Table 1: Eskom Electricity Sales and Revenues (FY07-FY09)
FY07
FY08
FY09
Customers
GWh
Rand
(million)
GWh
Rand
(million)
GWh
Rand
(million)
Redistributors
86,908
14,793
89,941
16,382
88,345
20,628
Industrial
59,822
9,657
61,510
10,629
54,815
11,887
Mining
32,421
5,503
32,373
5,825
32,177
7,439
Residential
4,423
1,753
4,694
1,965
4,558
2,396
Commercial
7,843
1,852
8,373
2,081
8,642
2,732
Agricultural
4,731
1,602
4,848
1,741
4,912
2,249
International
13,589
1,515
13,908
1,971
12,648
2,382
Other
8,383
4,000
8,719
3,054
8,753
4,113
218,120
39,389
224,366
43,521
214,850
52,996
5%
11%
3%
10%
-4%
22%
Total
Year to Year
increase
Historical Operating Costs
4.
The growth of Eskom’s operating-costs has significantly outpaced the growth of revenues
during the past several years. The Company’s operational expenses increased by 15 percent in
188
FY07, 21 percent in FY08 and 35 percent in FY09. The main driver of this growth was the rise in
the cost of generating electricity, (Primary Energy cost) which includes purchase of coal,
uranium, water, natural gas and diesel fuel used in the generation of electricity. The average
growth of Primary Energy costs was 33 percent during the last three years. In FY08, Primary
Energy expenses increased by 41 percent due to sharp increase in global commodity prices, while
the 38 percent increase in FY09 was mainly driven by Eskom management’s decision to increase
stock piles at power stations to 42 days from the average level of 13 days in FY08. The increase
in stock piles also resulted in additional coal purchases on a short-term basis. The average shortterm coal purchase price increased from 100 Rand/Ton in FY08 to 151 Rand/Ton in FY09.
5.
Staff costs are the second largest operational expense for Eskom. In FY09 it accounted
for 28 percent of the Company’s total operating expenses. To manage the large new build
program, Eskom reviewed its staff compensation strategy in order to attract and retain staff,
particularly those with scarce or critical skills. Given that Eskom’s skills to develop and manage
construction of large power stations were depleted over the last decade, this review and hiring of
new staff was deemed essential, but as expected resulted in a doubling of staff costs over the last
three years. The actual number of staff increased by 20 percent during the same period of time
from 31,548 in FY06 to 37,857 in FY09.
6.
Table 2 shows the operating-costs incurred by Eskom in FY06 - FY09. The operatingcosts are divided into Primary Energy and Other operating expenses that include Depreciation,
Staff and Maintenance costs.
Table 2: Eskom’s Operating Costs (FY06 to FY09, in Rand million)
FY06
FY 07
FY 08
FY 09
10,854
13,040
18,314
25,351
-
20%
41%
38%
18,091
20,269
22,204
28,673
Staff Costs
7,608
9,451
11,353
15,166
Maintenance
4,807
5,007
5,235
6,017
Depreciation
4,562
4,709
4,284
4,916
Other
1,114
1,102
1,332
2,574
12%
10%
29%
28,945
33,309
40,518
54,024
-
15%
21%
35%
Primary Energy
% increase over previous year
Total Other Operating expenses, of which
% increase over previous year
Total Operating expenses
Year to Year increase
Capital Investments
7.
As discussed earlier, Eskom witnessed falling reserve margins for electricity generation
from FY07 until the financial/economic crisis resulted in reduced demand for energy in FY09. In
response to the falling reserve margins, in FY07, Eskom initiated capital outlays for its New
Build and Major Maintenance Program. This massive investment program has forced Eskom to
significantly increase its investments in generation and transmission infrastructure: capital
expenditures more than quadrupled during the last three years and reached R47 billion in FY09.
Most of these investments, 68 percent or R31.8 billion, were used to build new generation
capacity. Commissioning of a new generation capacity increased from 170 MW in FY06 to 1,061
in FY08 and 1,770 in FY09. A summary of the Eskom’s capital expenditures during the past four
years is presented in Table 3 below.
189
Table 3: Eskom’s Capital Expenditures (FY06 to FY09, in Rand million)
Capital Expenditure, of which
Generation
Transmission
Distribution
Other
Year to Year increase
FY06
FY 07
FY 08
FY 09
10,616
5,023
1,263
4,027
1,114
-
17,707
10,439
1,993
4,695
1,102
67%
25,985
15,239
3.553
5,605
1,332
47%
47,099
31,824
6,465
6,446
2,574
81%
Funding Sources for Operations and Investments
8.
Cash from existing operations was the main source of funding for operating and capital
expenditures in FY06-FY07. Since FY08, Eskom’s investment expenditures have been largely
financed through issuance of new domestic debt (domestic bond issuances and commercial
paper), use of reserves accumulated in previous years, and support from the Government (of the
R60 Billion GoSA shareholder loan to Eskom approved in July 2008 is currently being
disbursed). Table 4 below provides a summary of Eskom’s funding sources in FY06-FY09.
Table 4: Eskom Funding Sources (FY06 to FY09, in Rand million)
FY06
FY 07
FY 08
FY 09
Cash from operations
12 346
13 281
(1,912)
11,764
Debt raised, incl. GoSA resources
19,179
15,324
16,831
53,959
Debt repaid
(9,382)
(6,903)
(9,092)
(23,492)
9,797
8,421
7,739
30,467
(2,210)
(1,807)
(3,154)
(3,869)
2 109
2 017
3,109
3,117
Net Debt stock
Interest paid
Interest received
9.
Eskom is supported by many bilateral/multilateral and commercial lenders. For the
purposes of financing the Medupi Power Plant Eskom has undertaken three large Export Credit
Agency supported and AfDB (public sector) financings (boilers/turbines) and has also secured
EIB, AfDB (private sector), and JICA financing for transmission lines and other investment
expenditures. In addition, it has commercial bank debt, government loans, domestic long-tenor
bonds, promissory notes and floating rate notes on its books.
Financial Ratios
10.
Eskom’s financial ratios have all deteriorated during the last three years due to rapid
growth of operating expenditures coupled with increase in borrowings needed to finance the
accelerated capital expenditures program. Table 5 below summarizes Eskom’s main financial
ratios.
11.
The operating margin, an indicator of operating efficiency and pricing adequacy has
dropped from around 33 percent in FY06 to 17 percent in FY07, to 8 percent in FY08 and
became negative 3 percent in FY09. Return on Total Assets decreased from 9.1 percent in FY06
to negative 0.8 percent in FY09, while Return on Average Equity dropped from 9.5 percent to
negative 16 percent during the same period. Interest cover ratio deteriorated from healthy 3.8 in
FY06 to negative 0.7 in FY09.
12.
The major reason for weakening of Eskom’s financial ratios is the fact that Eskom tariffs
have been growing much slower than the increase in operating and capital costs: the average
selling price of electricity during the last three years increased by 47 percent from 17.01 R
190
cents/kWh in FY06 to 24.97 R cents/kWh in FY09, while the average total cost of electricity sold
increased by 87 percent during the same period of time from 14.8 R cents/kWh in FY06 to 27.63
R cents/kWh in FY09. The average total cost of electricity sold was higher than the average
selling price in FY08 and FY09. The other important factor negatively affecting Eskom’s
financial performance is the increase in borrowings to finance significantly increased capital
expenditures: the debt to equity ratio for Eskom has risen from 0.2 in FY06 to 1.22 in FY09.
Table 5: Financial Ratios (FY06 to FY09)
Financial Ratios
Definition
FY06
FY07
FY08
FY09
Return on Total Assets (as a %)
Net Operating Income / Total assets
9.1
7.4
3.0
(0.8)
Return on Average Equity (as a %)
Net profit / Average Equity
Operating Margin (as a %)
Operating revenue / Operating
expenditure
9.5
7.6
(0.3)
(16.1)
32.8
17.4
7.8
(2.6)
Net Pre-tax Interest Coverage
(Profit before tax - Interest) / Interest
EBITDA Interest Coverage
EBITDA / Interest
2.8
2.7
1.0
(1.3)
4.0
3.3
2.0
0.9
Interest Cover
(EBITDA - Tax) / Interest
3.8
11.4
2.9
(0.7)
Liquidity
Current Assets / Current Liabilities
1.3
1.7
1.6
1.0
Debt to Equity
Debt / Equity
0.2
0.2
0.4
1.22
Credit Ratings
13.
Eskom’s current international rating is BBB+ rating from Standard and Poor’s and Baa2
rating from Moody’s. Both ratings have negative outlook, but are equal to the sovereign ratings of
the Republic of South Africa, reflecting the full ownership of Eskom by the GoSA. Current local
currency ratings of Eskom are A- with negative outlook from Standard and Poor’s, Baa2 with
negative outlook from Moody’s and National long term rating of AAA with stable output form
Fitch. As shown below in Table 6, Eskom’s ratings have declined in FY08-FY09 which reflects
the financial markets sentiment towards Eskom’s credit risk.
Table 6: Eskom’s Credit Ratings (FY05 to FY09)
Credit ratings and outlook
FY05
FY06
FY07
FY08
FY09
Standard and Poor’s
- Foreign currency
outlook
BBB
Stable
BBB+
Stable
BBB+
Stable
BBB+
Negative
BBB+
Negative
- Local currency
Outlook
Moody’s
- Foreign currency
outlook
AStable
AStable
AStable
ANegative
ADeveloping
Baa1
Stable
A2
Stable
A2
Stable
A2
Stable
Baa2
Negative
- Local currency
Outlook
Fitch Ratings
- National long term (zaf)
outlook
A3
Stable
A1
Stable
A1
Stable
A1
Review
Baa2
Negative
AAA
Stable
AAA
Stable
AAA
Stable
AAA
Stable
AAA
Stable
- National short term (zaf)
Outlook
FI+
Stable
FI+
Stable
FI+
Stable
FI+
Stable
FI+
Stable
14.
The ratings of Eskom reflect its dominant position in the South African electricity
market, 100 percent government ownership, an increasingly supportive regulatory regime
following the introduction of multiyear price reviews and material implicit and explicit support
191
from the Republic of South Africa during the crucial build program aimed at increasing
generation capacity. These strengths are adversely impacted by a very substantial, largely debtfinanced capital expenditure program necessitated by the tight reserve margin in South Africa and
a range of operational, cost, construction and financial risks associated with the program.
Eskom Financial Projections
15.
The following financial analysis — financial projections — aims to assess Eskom’s
ability to implement its operations, capital expenditure program and to maintain financial
sustainability without jeopardizing essential electricity service obligations. The following analysis
also takes into account the context under which Eskom is likely to operate, as the Country’s
premier utility mandated to provide reliable and affordable electricity which is a critical
imperative for sustainable economic growth in South Africa. These projections are the result of
extensive due diligence on the assumptions undertaken by Eskom which are discussed in this
Annex and Annex 1 of the PAD.
Electricity Tariffs
16.
Eskom's revenues are almost entirely regulated by tariffs set by the NERSA. The
Company's profitability and financial sustainability are dependent on NERSA’s approvals of
future multi-year tariff increases to cover the costs of building substantial new generation
capacity. In 2006, NERSA replaced its annual rate-of-return methodology with MYPD (Multi
Year Price Determination), a forward-looking, multiyear system that sets a predetermined tariff
over a three-year period. The new methodology is more transparent and provides more
predictability for Eskom’s future cash flows. The initial MYPD 1 application approved by
NERSA in February 2006, allowed for 5.1 percent tariff increase in FY06/07, 5.9 percent increase
in FY07/08 and 6.2 percent increase in FY08/FY09. However, strong inflationary pressures in
FY08-09 resulted in Eskom submitting an additional submission to NERSA, which approved
additional tariff increases of 14.2 percent in December 2007 and 11.7 percent in June 2008.
17.
On June 25, 2009, NERSA approved an interim FY10 tariff increase of 31.3 percent
following an application from Eskom for an increase of 34 percent. However, the effective tariff
for Eskom was 24.08 percent, because the 31.3 percent increase included the 2c/kWh
environmental levy payable to the GoSA. This interim tariff increase request was based primarily
on Eskom’s energy cost drivers and was proposed as a short-term intervention in the absence of
clearer long-term revenue requirements in the context of the massive investment plan that the
Company was undertaking. To protect the poor, NERSA limited the increase to the poor to 15
percent, thus resulting in an average increase to other customers of 36.7 percent. In addition, after
reviewing Eskom’s financial situation, including its projected capital expenditure and limitations
on borrowing needs, it provided indications for the future tariff path. A pricing cone was
projected with an upper and lower limit on the tariffs. The upper limit curve was calculated using
the submitted Eskom values for Operational expenditure, Capital expenditure and sales for FY11
and FY12, extrapolated for future years after FY12. The lower limit was estimated using
optimistic assumptions for cost reductions. The price cone indicated that the future MYPD2
determination could increase prices in a range of 30 percent to 60 percent per annum in nominal
terms, with the upper limit stabilizing in FY13 around R0.8/kWh in real FY09 values.
18.
In September 2009, Eskom submitted its MYPD2 application to NERSA requesting a 45
percent annual tariff increase for the next three years during FY10-FY13, which was within the
pricing cone indicated by NERSA. However, after extensive consultations with its stakeholders,
including the government, its high voltage customers, and feedback from the public, Eskom
revised its MYPD2 application and reduced its tariff increase request to 35 percent per annum for
the next three years FY10-FY13 which was resubmitted to NERSA on November 30, 2009.
192
19.
On February 24, 2010, NERSA completed review of the MYPD2 application and
announced its decision to allow Eskom to raise tariffs by 24.8% in FY 2011, 25.8% in FY 2012
and 25.9% in FY 2013. To protect the poor NERSA differentiated tariff increases for different
categories of residential customers: while the average cumulative price increase of electricity sold
by Eskom in FY11-FY13 will be 98%, the total cumulative price increase for customers
consuming less than 50 KWh of electricity per month will be only 11% and for customers
consuming more than 50 KWh, but less than 350 KWh per month will be 28%. Electricity Demand and Revenue Projections
20.
Electricity demand is closely correlated with GDP growth and in FY04-FY08 it was
growing by approximately 5 percent a year, in line with the expansion rate of the overall
economy in the country. In FY09, Eskom reported 4 percent drop in total electricity consumption,
mainly because of the reduction in electricity demand from the steel industry due to global
economic recession. In June-November 2009, Eskom conducted a comprehensive review of the
projected electricity demand in South Africa over the next ten years that included analysis of the
current economic situation in South Africa and input from major customer groups on their growth
prospects. According to this forecast, total electricity sales for Eskom are projected to increase at
an average rate of 2.8 percent during the next seven years, from 217 TWh in FY10 to 263 TWh in
FY17, which is lower than the expected long term average South African GDP growth of 3
percent during the same period of time. Table 7 below provides details of sales projections
provided by Eskom from FY10 to FY17.
Table 7: Electricity Sales Projections (GWh)
FY10
FY11
FY12
FY13
FY14
FY15
FY16
FY17
FY18
FY19
Domestic Sales
204,654
213,285
219,182
224,331
228,907
232,835
240,169
249,351
258,254
267,784
Export Sales
12,674
14,992
14,266
13,851
13,553
13,670
13,949
13,956
13,991
14,029
Total Sales
217,328
228,276
233,448
237,911
242,460
246,505
254,118
263,307
272,245
281,813
Year to Year
increase
1.0%
5.0%
2.3%
1.9%
1.9%
1.7%
3.1%
3.6%
3.4%
3.5%
21.
Eskom’s electricity sales revenues are projected to increase from R70 billion in FY10 to
R148 billion in FY13. The projected revenue growth is mainly driven by the growth in tariff179 as
demand for electricity is forecasted to grow at CAGR of around 3 percent during the forecasted
period. Table 8 below presents revenue projections from FY2010 to FY2017. With lower than
anticipated tariff increases provided by NERSA, Eskom’s revenues are projected to result in a
cash flow shortfall over the next three years until MYPD 3 is submitted.
Table 8: Revenue Projections (in Rand millions)
FY10
FY11
FY12
FY13
FY14
FY15
FY16
FY17
67,413
87,617
112,387
143,844
181,559
229,085
250,367
275,444
33%
30%
28%
28%
26%
26%
9%
10%
2,766
3,310
3,765
4,534
5,286
5,795
6,125
6,795
%, change
-17%
20%
14%
20%
17%
10%
6%
11%
Total Revenue
70,179
90,927
116,152
148,378
186,845
234,880
256,492
282,239
32%
30%
28%
28%
26%
26%
9%
10%
Domestic
Revenues
%, change
Export
Revenues
%, change
179
Projected tariff increases are 24.8% in FY 2011, 25.8% in FY 2012 and 25.9% in FY 2013 (as per NERSA decision
on the MYPD2 application), followed by 25% in FY2014-15 and inflation plus 1% in FY 2016-17.
193
Operating Expenses
22.
Eskom’s total operating expenses are projected to increase from R66 billion in FY10 to
R181 billion in FY17, a CAGR of 16 percent. Primary energy expenses which constitute almost
half of total operating-costs are expected to increase at a CAGR of 18 percent. However, the main
driver of the operating expenses growth will be increased generation of electricity: the average
total unit cost of electricity sold will increase from R35 cents in FY10 to R76 cents in FY17
which translates into CAGR of only 12 percent. A summary of operating expenses projections is
in Table 9 below.
Table 9: Operating Expenses (FY 10 to FY19, in Rand millions)
Primary Energy
FY10
FY11
FY12
FY13
FY14
FY15
FY16
FY17
29,071
42,213
48,789
55,311
64,946
72,144
83,462
90,861
%, change
15%
45%
16%
13%
17%
11%
16%
9%
Manpower
14,616
16,226
17,552
18,910
20,719
22,785
26,095
28,507
%, change
3%
11%
8%
8%
10%
10%
15%
9%
Depreciation
5,956
7,630
8,924
10,902
13,463
16,361
20,188
23,361
%, change
31%
28%
17%
22%
23%
22%
23%
16%
15,919
19,342
21,174
23,687
25,946
29,415
35,217
38,147
31%
18%
9%
11%
9%
12%
16%
8%
65,562
85,411
96,439
108,810
125,074
140,705
164,962
180,876
19%
30%
13%
13%
15%
12%
17%
10%
O&M
%, change
Total Operating Expenses
%, change
Capital Investment Program
23.
Assuming Eskom’s current role to be responsible for security of supply and to undertake
the required massive New Build Program, it would need to spend around R702 billion on capital
investments over the next seven years. About R497 billion or 71 percent of the total amount will
be spent on generation and transmission.180 Investments in distribution (R117 billion or 17
percent of the total) will be aimed at strengthening and refurbishment of existing networks.
Eskom’s major generation capital investment projects are noted in Annex 1.
24.
Over the next five years, Eskom is planning to undertake R464 Billion of investments,
primarily on the Ingula, Medupi and the other generation projects. The table below provides a
summary of Eskom’s planned capital expenditures in FY10-FY17.
Table 10: Eskom’s Capital Expenditure Program (FY10-FY19, in Rand millions)
Capital
Expenditure
FY10
FY 11
FY 12
FY 13
FY14
FY15
FY16
FY17
Generation
36,529
63,228
69,546
53,579
34,953
49,118
76,674
93,292
Transmission
7,582
14,533
11,327
16,112
16,667
22,099
23,897
24,216
Distribution
5,338
8,355
10,466
12,496
14,571
16,793
19,817
21,789
Other
1,328
1,531
3,078
4,051
2,592
895
7,566
2,614
Total
50,777
87,646
94,417
86,239
68,783
88,905
126,492
156,703
% increase
36,529
63,228
69,546
53,579
34,953
49,118
76,674
93,292
180
Investments in transmission are mostly expansions of the existing grid to allow integration of new power plants.
194
Eskom’s Financial Recovery Plan and Financing Assumptions
25.
Based on financing projections carried out, based on available and current information
about Eskom’s operating and investment program, it is projected that the Company would need to
raise around R440 billion (US$60 billion) of cash flow during the next 7 years to fully implement
its planned capital expenditures program. Clearly, this is a large amount of financing to be
generated. At present, Eskom plans suggest that it would require R264 billion (US$35 billion) of
this amount to be funded in FY11-FY13. Financial projections indicate that tariff increases alone
approved by NERSA for FY11-FY13 will not allow Eskom to generate sufficient cash flows to
fully implement its capital investments program. In order to maintain financial sustainability in
the near term, Eskom would need to adjust its capital investments program by
canceling/postponing certain projects (other than Medupi) and/or obtain additional support from
GoSA in the form of additional equity injection and/or shareholder loan.
26.
Given the strategic importance of Eskom’s build program for the South African economy
and the limited ability of the Company to attract funding on commercial terms without
jeopardizing its credit ratings, the government has already provided Eskom with a shareholder
loan and debt guarantees. In July 2008, the National Treasury approved a R60 billion interest
free subordinated loan to Eskom. R40 billion of this amount was disbursed in FY08-10, while
the remaining portion will become available to Eskom in FY11 (R20 billion). In February 2009,
the South African government announced that it will directly guarantee R26 billion of Eskom’s
existing debt and an additional R150 billion of new debt over the next five years. In FY10,
Eskom utilized approximately R60 billion of the guarantees provided by the South African
government. Undisbursed portion of the Shareholder loan and unutilized debt guarantees will
provide Eskom with R110 billion or 42 percent of its total external funding needs during the
FY11-FY13 period, meaning that the Company would need to raise R154 billion from other
sources of financing.
27.
Eskom’s ability to fully implement its near to medium term capital expansion plan is thus
based on assumption that this large financing, provided without GoSA guarantees will
materialize. Given the current financial position of the Eskom, it is unlikely that it will be able to
borrow the required R154 billion financing in FY11-FY13 on the international markets without
the support from either the GoSA or other agencies. The GoSA and Eskom realize this problem
and are currently considering the option of bringing in private participation in the next coal plant
in such a manner that Eskom’s does not have to finance some of the capital expenses associated
with its construction costs – possibly as a PPP scheme. If the next coal fired plant is further
developed as an IPP, a private sector investor will assume the responsibility to complete the
construction of the plant and sell power to the Single Buyer under a PPA. Implementation of this
plan would reduce Eskom’s funding needs in FY11-FY13 by R79 billion meaning that the
company will be required to raise only R75 billion on commercial terms during this period of
time.
28.
Eskom’s long term financial sustainability is dependent on its ability to secure additional
annual tariff increases of around 25 percent in its MYPD3 application for FY14-FY15 period to
be able to service its debt obligations and implement the remaining portion of its capital
expenditure plan. Securing of such increase would be in line with the existing MYPD
methodology that allows recovery of capital expenditures through tariff increases. Table 12
below presents expected financial performance of Eskom assuming implementation of NERSA’s
decision on MYPD2 application (tariff increases of 24.8% in FY11, 25.8% in FY12 and 25.9%
in FY13), approval of MYPD3 application as described above (25% increase in FY14 and FY15),
and inflation plus 1% tariff increase in FY16-FY17.
195
Expected Financial Performance and Projected Ratios
29.
The base case financial projections, under the assumptions noted above, indicate that the
Eskom will be able to maintain reasonable profitability and generate sufficient cash flows to
implement its capital investments program and service the debt throughout the projection period.
A summary of the projected financial performance and main ratios is presented in Table 11
above.
Table 11: Expected Financial Performance and Projected Ratios (FY10-FY19)
Revenues
%, change
Operating Costs, Including:
FY10
FY11
FY12
FY13
FY14*
FY15*
FY16*
FY17*
70 179
32%
90 927
30%
116 152
28%
148 378
28%
186 845
26%
234 880
26%
256 492
9%
282 239
10%
65,562
85,411
96,439
108,810
125,074
140,705
164,962
180,876
Primary Energy
Manpower
O&M
EBITDA
29,071
14,616
15,919
42,213
16,226
19,342
48,789
17,552
21,174
55,311
18,910
23,687
64,946
20,719
25,946
72,144
22,785
29,415
83,462
26,095
35,217
90,861
28,507
38,147
10,573 13,146
28,637
50,470
75,234
110,536
111,718
124,724
Depreciation
Interest
Taxes
Other Expenses
Net Profit
5,956
2,387
- 967
5597
7,630
5,088
145
0
8,924
8,609
3,131
0
10,902
13,442
7,357
0
13,463
15,287
12,947
0
16,361
18,197
21,207
34
20,188
22,203
19,344
66
23,361
22,876
21,911
70
-2,400
283
7,973
18,769
33,537
54,737
49,917
56,506
10,878
16,143
28,912
48,237
73,153
112,291
121,418
130,681
Capital Expenditures
50,777
87,649
94,420
86,243
68,784
88,905
127,954
139,297
Debt Service
-11,982
20,519
27,517
40,634
44,768
42,045
50,629
51,819
Cash from Operations
Funding Requirement
27,917
92,025
93,025
78,640
40,399
18,659
57,165
60,435
Assets, including:
216,836
328,258
416,234
516,640
595,855
713,718
834,066
963,916
Non-current assets
Current Assets
Liabilities, including:
202,246
14,590
291,989
36,269
391,873
24,361
486,433
30,207
559,773
36,082
650,035
63,683
775,154
58,912
911,659
52,257
148,250
250,386
320,389
392,025
427,703
480,833
551,274
624,628
128,540
19,710
68,588
223,260
27,126
77,872
289,104
31,285
95,845
356,462
35,563
124,613
393,996
33,707
168,151
441,029
39,804
232,884
502,424
48,850
282,792
570,054
54,574
339,289
216,836
328,258
416,234
516,640
595,855
713,718
834,066
963,916
Debt/Equity
1.50
2.29
2.66
2.50
1.97
1.43
1.34
1.26
DSCR
1.06
0.70
1.14
1.32
1.77
2.72
2.23
2.44
Current Ratio
0.74
1.34
0.78
0.85
1.07
1.60
1.21
0.96
EBITDA Margin
15%
14%
25%
34%
40%
47%
44%
44%
Non-current Liabilities
Current Liabilities
Equity
Total Equity and Liabilities
Key Ratios
*Based on MYPD2 Application and Staff Estimates
Financial Analysis of Projects Financed by the IBRD Loan
Component A – The Medupi Power Plant
30.
Capital Costs and Financing Plan: The project base capital-costs are expected to be R83.2
billion in nominal terms. An additional R6.0 billion are considered as Eskom’s development costs
associated with the project and R9.3 billion are allocated for contingencies on placed and
unplaced contracts resulting in an overall project cost of about R98.5billion (for funding
purposes). The total cost of the Medupi Power Plant is estimated at R125.7 billion including
interest during construction. Approximately R18.6 billion or 15 percent of the total project cost
was expended in FY07-FY09, while the remaining costs are expected to be incurred in FY10FY16.
196
31.
It is expected that the project will be funded through debt facilities from IBRD (R825
million), CTF (R750 million) and AFD (R750 million). The loan disbursements will start in
FY11. IBRD will also finance interest during construction for its own debt tranche for the project.
Remaining estimated financing needs of about R1,056 million or 31 percent of the total project
costs on are expected to be financed by Eskom and other lenders such as AfDB and other
bilaterals.
32.
Operating Assumptions: The proposed investment is expected to generate revenues of
R1.11/kWh (in 2009 Rands). This assumption is based on NERSA’s announcement on REFITs
on October 29, 2009 in which the regulator indicated that it would allow renewable energy
producers to recover the real weighted average cost of capital (12 percent) plus the rate of
domestic inflation (6 percent). Under the base case assumptions the project is expected to result in
18 percent FIRR for Eskom. These revenues are assumed to grow at the rate of domestic
inflation. The average plant load factor is estimated to be 25 percent. Operations and maintenance
costs are assumed to be R96/kW/year plus 11.7 EUR /kW/year as per Eskom estimates.
Transmission and distribution losses are estimated at 11 percent, while transmission and
distribution expenses are projected to be around 15 percent of the total plant revenues in line with
the current Eskom average. The total useful life of the project is estimated at 20 years.
33.
Projected Project Cashflow: Total revenues of the project during its 20 years of operation
period are projected at R8.4 billion. Total operating-costs of the plant during its useful life period
are estimated around R805 million, while transmission and distribution expenses are expected to
reach R1.3 billion. Projected total EBITDA of the project is around R6.3 billion.
34.
Financial Rate of Return and Net Present Value: Under the base case scenario, it is
expected that the project will have a FIRR of 6.8 percent. The NPV of the project is estimated at
negative R678 million (about US$90 million), assuming a discount rate of 10.3 percent, which is
Eskom’s current estimated average weighted cost of capital. The FIRR for the equity component
of the project (Eskom’s own capital) is estimated to be 18 percent, while the nominal NPV for
Eskom is estimated to be R398 million (about US$53 million). The NPV and IRR are higher for
Eskom due to significant leveraging of the project: approximately 69 percent of the project capital
is expected to be financed by loans directly associated with the Sere Wind Power Project.
35.
Sensitivity Analysis: A sensitivity analysis was conducted to assess the financial viability
of the project. Scenarios examined include: (a) Project implementation delay of one year (FY14
commissioning of the plant) and payment of contingencies (R303 million in FY11-FY14); (b)
Lower than expected REFIT: 10 percent less than the current expected tariff at commissioning;
(c) Construction cost overruns of 10 percent; and (d) Decrease in Load Factor of the Plant by 10
percent.
36.
The results of the sensitivity analysis are shown below in Table 12. The analysis shows
that although on a standalone basis the project is likely to result in negative NPV under all of the
sensitivity scenarios, the availability of long term funding from CTF and IBRD would allow
Eskom to achieve positive financial returns under the base case, and all sensitivity scenarios with
the exception of the Worst Case Scenerio. Financial performance of the project is most sensitive
to implementation delays and the load factor of the plant associated with wind i.e. average wind
availability during the year for operation of the plant.
197
Table 12: Medupi Power Plant - Sensitivity and Scenario Analyses
Project IRR
Project NPV
(Rand
billions)
Eskom IRR
Eskom NPV
(Rand
billions)
Base Case
17.5%
117
21.4%
129
Project implementation delay (1 year)
16.1%
105
18.9%
116
Lower than anticipated Tariff Increases
14.1%
54
16.7%
66
Construction cost overruns of 10%
16.8%
112
20.1%
123
Increase in O&M Costs, incl. coal of 5%
17.4%
116
21.2%
128
Worst Case Scenario (Combination of
the above)
13.0%
42
14.8%
54
Scenario
Component B.1 – The Sere Wind Power Project (100 MW)
37.
Capital Costs and Financing Plan: The project base capital-costs are expected to be
R2,759 million in nominal terms. An additional R284 million are considered as Eskom’s
development costs associated with the project and R303 million are allocated for contingencies
on unplaced contracts resulting in an overall project cost of about R3,347 million. The total cost
of the Sere Wind Power Project is estimated at R 3,381 billion including interest during
construction. These costs are expected to be incurred in FY10-FY14 and the first electricity
production is projected in FY13.
38.
It is expected that the project will be funded through debt facilities from IBRD (R825
million), CTF (R750 million) and other DFIs (R750 million). The loan disbursements will start in
FY11. IBRD will also finance interest during construction for its own debt tranche for the project.
Remaining estimated financing needs of about R1,056 million or 31 percent of the total project
costs on are expected to be financed by Eskom and other lenders such as AfDB and other
bilaterals.
39.
Operating Assumptions: The proposed investment is expected to generate revenues of
R1.11/kWh (in 2009 Rands). This assumption is based on NERSA’s announcement on REFITs
on October 29, 2009 in which the regulator indicated that it would allow renewable energy
producers to recover the real weighted average cost of capital (12 percent) plus the rate of
domestic inflation (6 percent). Under the base case assumptions the project is expected to result in
18 percent FIRR for Eskom. These revenues are assumed to grow at the rate of domestic
inflation. The average plant load factor is estimated to be 25 percent. Operations and maintenance
costs are assumed to be R96/kW/year plus 11.7 EUR /kW/year as per Eskom estimates.
Transmission and distribution losses are estimated at 11 percent, while transmission and
distribution expenses are projected to be around 15 percent of the total plant revenues in line with
the current Eskom average. The total useful life of the project is estimated at 20 years.
40.
Projected Project Cashflow: Total revenues of the project during its 20 years of operation
period are projected at R8.4 billion. Total operating-costs of the plant during its useful life period
are estimated around R805 million, while transmission and distribution expenses are expected to
reach R1.3 billion. Projected total EBITDA of the project is around R6.3 billion.
41.
Financial Rate of Return and Net Present Value: Under the base case scenario, it is
expected that the project will have a FIRR of 6.8 percent. The NPV of the project is estimated at
negative R678 million (about US$90 million), assuming a discount rate of 10.3 percent, which is
Eskom’s current estimated average weighted cost of capital. The FIRR for the equity component
of the project (Eskom’s own capital) is estimated to be 18 percent, while the nominal NPV for
Eskom is estimated to be R398 million (about US$53 million). The NPV and IRR are higher for
198
Eskom due to significant leveraging of the project: approximately 69 percent of the project capital
is expected to be financed by loans directly associated with the Sere Wind Power Project.
42.
Sensitivity Analysis: A sensitivity analysis was conducted to assess the financial viability
of the project. Scenarios examined include: (a) Project implementation delay of one year (FY14
commissioning of the plant) and payment of contingencies (R303 million in FY11-FY14); (b)
Lower than expected REFIT: 10 percent less than the current expected tariff at commissioning;
(c) Construction cost overruns of 10 percent; and (d) Decrease in Load Factor of the Plant by 10
percent.
43.
The results of the sensitivity analysis are shown below in Table 13. The analysis shows
that although on a standalone basis the project is likely to result in negative NPV under all of the
sensitivity scenarios, the availability of long term funding from CTF and IBRD would allow
Eskom to achieve positive financial returns under the base case, and all sensitivity scenarios with
the exception of the Worst Case Scenerio. Financial performance of the project is most sensitive
to implementation delays and the load factor of the plant associated with wind i.e. average wind
availability during the year for operation of the plant.
Table 13: Sere Wind Power Project - Sensitivity and Scenario Analyses
Project IRR
Project NPV
(Rand
millions)
Eskom IRR
Eskom NPV
(Rand
millions)
6.8%
-678
18%
398
Project implementation delay (1 year)
5.3%
-1,073
10.3%
2
Lower than anticipated REFITs (by 10%)
5.6%
-885
14.1%
190
Construction cost overruns of 10%
6.0%
-891
13.0%
185
Decrease in Load Factor by 10%
5.6%
-885
14.0%
190
Worst Case Scenario (Combination of
above)
2.4%
-1,671
3.3%
-596
Scenario
Base Case
44.
Additional analysis of the project has been carried out to include potential revenues
resulting from the sales of carbon credits. The following assumptions were utilized for these
calculations: the South African grid emission factor (the amount of carbon emissions associated
with each unit of electricity in an electricity grid) was estimated at 1.02 and realization price of
carbon credits was projected at US$10/ton. Based on these assumptions, sales of carbon credits of
the wind project are expected to generate US$2.2 or R298 million annually. The impact of these
cash flows on the Eskom’s IRR and NPV of the project will be minimal: the IRR would increase
by 0.04 percent, while the NPV is expected to increase by R2 billion.
Component B.2 – The Upington Concentrating Solar Power Project (100 MW)
45.
Capital Costs and Financing Plan: The project base capital-costs are expected to be
R4,670 million in nominal terms. An additional R75 million are considered as Eskom’s
development costs associated with the project and R1,125 million are allocated for contingencies
on unplaced contracts resulting in an overall project cost of about R5,870 million for funding
purposes. The total cost of the Upington CSP is estimated at R6,040 million including interest
during construction. These costs are expected to be incurred in FY10-FY14 and the first
electricity production is projected in FY14.
46.
Approximately 50 percent of the project’s total cost will be funded through debt facilities
from IBRD (R1,125 million) and CTF (R1,870 million). The loan disbursements will start in
FY11. IBRD will also finance Interest during Construction for its own debt tranche for the
project. Remaining estimated financing needs of about R3,045 million are expected to be
financed by Eskom.
199
47.
Operating Assumptions: The proposed investment is expected to generate revenues of
R1.49/Kwh (in 2009 Rands). This assumption is based on the NERSA’s announcement on
Renewal Energy Feed-in Tariffs (REFITs) on October 29, 2009 in which the regulator indicated
that it would allow renewable energy producers to recover the real weighted average cost of
capital (12 percent) plus the rate of domestic inflation (6 percent). Under our base case
assumptions the project is expected to result in 18 percent FIRR for Eskom. Even though it is
intended to design the plant for a load factor of 60-65 percent, because of the limited long-term
experience with the technology, the financial analysis is based on a conservative load factor of 40
percent. Operations and maintenance cost are assumed to be R1,090/kW/year of capacity, while
variable operations and maintenance costs are projected at R12.9 / MW/hr (in FY10 prices) as per
Eskom estimates. Transmission and distribution losses are estimated at 11 percent, while
transmission and distribution expenses are projected to be around 15 percent of the total plant
revenues in line with the current Eskom average. The total useful life of the project is estimated at
20 years.
48.
Projected Project Cashflow: Total revenues of the project during its 20 years operation
period are estimated at R18.8 billion, while the total operating-costs of the plant during its useful
life period are estimated at R4.6 billion. Transmission and distribution expenses are expected to
reach R2.8 billion. Projected total EBITDA of the project is R11.4 billion.
49.
Financial Rate of Return and Net Present Value: Based on the financial analysis carried
out for the project, the Upington CSP Project is expected to be financially viable for Eskom.
Under the base case scenario, it is expected that the project will have a Financial Rate of Return
(FIRR) of 7.6 percent. The nominal Net Present Value (NPV) of the project is estimated at
negative R909 million (about US$121 million), assuming a discount rate of 10.3 percent, which is
Eskom’s current estimated average weighted cost of capital. The FIRR for the equity component
of the project (Eskom’s own capital) is estimated to be 18 percent, while the nominal NPV for
Eskom is estimated to be R1,094 million (about US$254 million). The NPV and IRR are higher
for Eskom due to significant leveraging of the project - approximately 50 percent of the project
capital is expected to be financed by loans from IBRD and CTF.
50.
Sensitivity Analysis: A sensitivity analysis has been conducted to assess the financial
viability of the project. Scenarios examined include: (a) Project implementation delay resulting in
commissioning of the plant in FY15 and payment of contingencies (R1,125 million in FY11FY14) ; (b) Lower than expected REFIT: 10 percent less than the current expected tariffs at
commissioning; (c) Construction cost overruns of 10 percent of base project costs; and (d)
Decrease in Load Factor of the Plant by 10 percent.
51.
The results of the sensitivity analysis are shown below in Table 14. A review of this
analysis shows that the project viability is highly sensitive to: project implementation delays,
lower REFIT tariffs and the changes to the load factor of the plant, i.e. average solar intensity and
solar availability during the operations of the plant. The outcome of the analysis indicate that
although Upington CSP Project is not financially viable for Eskom on a standalone basis,
availability of long term, low cost financing from CTF and IBRD will allow Eskom to achieve
healthy 18 percent FIRR under the base case assumptions and positive NPV under most of the
sensitivity scenarios.
Table 14: Upington CSP Project - Sensitivity and Scenario Analyses
Project IRR
Project NPV
(Rand
millions)
Eskom IRR
Eskom NPV
(Rand
millions)
Base Case
7.6%
-909
18%
1,094
Project implementation delay (1 year)
5.0%
-2,112
9.8%
-108
Scenario
200
Project IRR
Project NPV
(Rand
millions)
Eskom IRR
Eskom NPV
(Rand
millions)
Lower than anticipated REFITs (by 10%)
6.1%
-1,336
15.3%
668
Construction cost overruns of 10%
6.7%
-1,298
14.4%
705
Decrease in Load Factor by 10%
6.1%
-1,331
15.3%
673
Worst Case Scenario (Combination of the
above)
1.7%
-3,342
4.4%
-1,339
Scenario
52.
Additional analysis of the project has also been carried out to include potential revenues
resulting from the sale of carbon credits. The following assumptions were utilized for these
calculations: the South African grid emission factor (the amount of carbon dioxide emissions
associated with each unit of electricity in an electricity grid) was estimated at 1.02 and realization
price of carbon credits was projected at US$10/ton. Based on these assumptions, sales of carbon
credits of the wind project are expected to generate US$6.3 or R477 million annually. The impact
of these cash flows on the Eskom’s IRR and NPV of the project will be minimal: the IRR would
increase by 0.1 percent, while the NPV is expected to increase by R3 billion.
Component C.1 – The Majuba Rail Project
53.
Capital Costs and Financing Plan: The project base capital-costs are expected to be
R2,672 million in nominal terms. An additional R477 million are considered as Eskom’s
development costs associated with the project and R383 million are allocated for contingencies
on placed and unplaced contracts resulting in an overall project cost of about R3,532 billion for
funding purposes. The total cost of the Majuba Rail Project is estimated at R4,234 million
including interest during construction. Eskom began development and pre-investment
expenditures on the project in FY08 and approximately R173 million or 5 percent of the total
project cost has been spent in FY08-FY09. The remaining costs are expected to be incurred in
FY10-FY14.
54.
It is expected that the project will be mostly funded through debt facilities from IBRD
(R3, 375 or US$450 million). IBRD will also finance interest during construction for its own debt
tranche for the project. Remaining financing needs of about R859 million are expected to be
financed by Eskom.
55.
Operating Assumptions: The Majuba Rail project involves construction of a 68 km
railway line from the west of Ermelo to the existing Majuba Power Plant. The railway line will
change coal supply logistics to the Majuba Power Plant from a combination of road transport
(700 trucks per day or 7 million tons/year) and rail using the GFB network (6 million tons/year)
to the new rail link which will transport around 13 million tons of coal per year and reduce the
average haul distance by 150 km. The new line is expected to be commissioned in January 2014.
56.
The main financial benefit of the project is reduction of operating-costs to Eskom. The
current cost of transporting the coal via road is R74.3/ton and the average cost of rail transport
using the GFB is R83.2/ton. The new Majuba line will transport almost all the coal consumed by
Majuba power plant. The coal is planned to be supplied from five mines in the Witbank area. The
new line will be operated by Transnet Freight Rail (TFR), state owned rail freight operator of
South Africa. A Coal Transportation Agreement (CTA) is under development between TFR and
Eskom. The CTA will include the terms and conditions for the operation of the transportation of
coal in the Majuba line using rolling stock supplied, maintained and managed by TFR. Although
the CTA has not been finalized, the parties reached a preliminary agreement that the coal
transportation tariff that TFR will charge Eskom for the operation of the line will be R24.27/ton.
201
57.
Eskom will be responsible for the maintenance of the infrastructure, including the
signaling and electrification equipment. The total annual maintenance costs are estimated at R12
million. It is also projected that the amount of coal consumed by the Majuba power plant will
gradually decrease from 13 MTpa in FY14 to 9.9 MTpa in FY44 due to aging of the plant and
decline of its generation capacity. For the purposes of the financial analysis, all costs are expected
to grow in line with inflation rate.
58.
Projected Project Cashflow: The total amount of savings that the project is projected to
generate after the new line becomes operational in FY14 is estimated to be about R60 billion per
annum. These savings are calculated as the difference between the cost of maintaining the current
mode of coal transport (combination of road and rail) and the use of the new Majuba rail line. The
maintenance cost during the useful life of the project is expected to reach R1.1 billion, while the
total capital expenditures will be around R3,149 million.
59.
Financial Rate of Return and Net Present Value: Based on the financial analysis carried
out for the project, the Majuba Rail Project is expected to be financially viable. Under the base
case scenario, it is expected that the project will have a Financial Rate of Return (FIRR) of 30.3
percent. The NPV of the project is estimated at R5,687million (about US$ 758 million), assuming
a discount rate of 10.3 percent, which is Eskom’s current estimated average weighted cost of
capital. The FIRR for the equity component of the project (Eskom’s own capital) is estimated to
be 69.5 percent, while the nominal NPV for Eskom is estimated to be R6,528 million (about
US$870 million). The NPV and IRR are higher for Eskom due to significant leveraging of the
project - around 80 percent of the project capital is expected to be financed by loans directly
associated with the Majuba Rail Project from IBRD.
60.
Sensitivity Analysis: A sensitivity analysis has been conducted to assess the financial
viability of the project. Scenarios that have been tested include: (a) Project implementation delay
resulting in commissioning of the rail in FY15 (vs. FY14 in the base case) and payment of
contingencies (R383 million in FY11-FY14); (b) Higher than expected transportation tariff: 20
percent more than the current expected agreement between Eskom and TFR.; (c) Construction
cost overruns of 10 percent of base project costs; and (d) Increase in O&M costs of 5 percent over
and above the projected inflation rate.
61.
The results of the sensitivity analysis are shown below in Table 15. A review of this
analysis shows that the project is financially viable in all cases, including the worst case scenario
(all downside sensitivities occur at the same time). The project viability is sensitive to
implementation delay and transportation tariff charged by TFR for the proposed project. The
project is relatively immune to construction cost overruns and increase in O&M costs.
Table 15: Majuba Rail Project - Sensitivity and Scenario Analyses
Project IRR
Project NPV
(Rand millions)
Eskom IRR
Eskom NPV
(Rand millions)
Base Case
30.3%
5,687
69.5%
6,528
Project implementation delay (1 year)
24.7%
4,957
52.7%
5,779
Higher than anticipated transportation
tariff
28.9%
5,206
68.1%
6,048
Construction cost overruns of 10%
28.6%
5,530
63.0%
6,372
Increase in O&M Costs by 5%
30.2%
5,567
69.5%
6,408
Worst Case Scenario (Combination of
the above)
22.4%
4,232
45.7%
5,074
Scenario
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Annex 11: Safeguard Policy Issues
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Executive Summary of Safeguard Diagnostic Review prepared by the Bank under OP 4.00
BP 4.00 requires that for projects in which safeguards are being addressed through the use of country
systems, the findings of the Safeguards Diagnostic Review are summarized in an annex to the PAD. It is
standard procedure to accomplish this by reproducing the Executive Summary of the Safeguards
Diagnostic Review (SDR) in this annex.
1.
Policy Framework. Under Operational Policy/Bank Procedure 4.00 (OP/BP 4.00),
Piloting the Use of Borrower Systems to Address Environmental and Social Safeguard Issues in
Bank-Supported Projects, the Bank has had the authority since March 2005 to support pilot
projects in which lending operations are prepared using the borrowing country’s systems for
environmental and social safeguards, rather than the Bank’s corresponding operational policies
and procedures. The advantages of using country systems (UCS) are to: scale up development
impact, increase country ownership, build institutional capacity, facilitate donor harmonization in
approaches to environmental and social safeguards, and increase cost effectiveness. These
objectives with respect to environmental and social safeguards were broadly endorsed at the Paris
High Level Forum on Aid Effectiveness in March 2005, and strongly reiterated in the Accra
Agenda for Action in September 2008.
2.
During the past three years, the World Bank has approved ten pilot projects under the
first phase of this program, including recent approval of a pilot project in South Africa. On
January 31, 2008, the Executive Directors of the World Bank approved a three-year extension of
the pilot program accompanied by an incremental scaling up of the pilots from the project to the
country-level, including support of activities at the sub-national level. Under the three-year
extension, i.e., the second phase of the pilot program, nine pilots have been formally initiated and
are being worked on, including a scaled up second project in South Africa for which this
document has been prepared.
3.
OP/BP 4.00 describes the approach, enumerates the criteria for using country systems,
and specifies documentation and disclosure requirements and respective roles of the borrower and
the Bank. The Bank considers a borrower’s environmental and social safeguard system to be
equivalent to the Bank’s if the borrower’s system is designed to achieve the objectives and adhere
to the applicable operational principles set out in Table A1 of OP 4.00. Since equivalence is
determined on a policy-by-policy basis in accordance with Table A1, the Bank may conclude that
the borrower’s system is equivalent to the Bank’s with respect to specific environmental or social
safeguards in particular pilot projects, and not with respect to others. Before deciding on the use
of borrower systems, the Bank also assesses the acceptability of the borrower’s institutional
capacity, implementation practices, and past performance in similar projects. Gap-filling
measures must be implemented prior to project approval or, if carried out by necessity during
project implementation, are subject to a time-bound legal agreement between the Bank and the
borrower. The process and product of analyzing equivalence, assessing eligibility, and identifying
and agreeing on gap-filling measures is called a Safeguards Diagnostic Review (SDR). Under OP
4.00, a draft SDR is required to be disclosed prior to project appraisal.
4.
This SDR is prepared for the Eskom Investment Support Project (EISP) in South Africa.
The project has been requested by the Government of South Africa (GoSA) to support selected
investments by Eskom Holdings Ltd. (Eskom) in the power sector. The SDR describes the scope,
methodology, and findings of the equivalence analysis and acceptability assessment carried out in
South Africa by staff from the World Bank. It also identifies and proposes gap-filling measures
designed to ensure that applicable South African safeguard systems, and Eskom’s corporate
practices for complying with the relevant South African regulations, meet the equivalence and
203
acceptability criteria of OP 4.00 throughout the project cycle and are adapted to extend their
benefits beyond the scope of the project to the extent possible. The SDR was conducted in
collaboration with the borrower, which is Eskom, and officials from the South African Ministry
of Water and Environmental Affairs, including the Department of Environmental Affairs
(DoEA).181 A draft of this SDR was publicly disclosed by the Bank and by Eskom in November
2009, and was the subject of stakeholder consultation workshops held in South Africa in early
December 2009. This revised document takes into consideration comments received from
stakeholders, and is being disclosed by the Bank and by Eskom.
5.
Project Objectives. The strategic objectives of the EISP are to: (a) support the GoSA in
removal of the growing infrastructure bottlenecks on an accelerated basis; and (b) revive
economic growth in the Southern Africa region through enhancement of South Africa’s power
supplies in an efficient and sustainable manner to bridge current and projected electricity supplydemand imbalances that already have taken a toll on sustained regional as well as South Africa’s
economic growth. The objective of the SDR is to assess the borrower’s safeguards systems, and
for this purpose the SDR has looked at safeguards documents prepared for several Eskom
investment projects, not all of which would receive Bank support.
6.
Project Components. The proposed Project, which will be implemented by Eskom, will
consist of three Components. Section II.C of the PAD provides further details.
7.
For purposes of assessing the implementation practices, track record, and institutional
capacity of Eskom and the South African regulatory institutions that will be involved in
addressing environmental and social safeguard issues in the proposed Bank-supported EISP, the
Medupi Power Plant and another major Eskom investment currently under construction, the 4,800
MW Kusile power plant in Mpumalanga Province, were selected by the Bank team to assess and
verify the robustness of the Environmental Impact Assessment (EIA) process and its outputs
under the requirements of OP 4.00. By selecting these two nationally important projects as the
primary subjects of SDR analytical work for the EISP, the Bank achieves two important
objectives: it allows the SDR to assess the integrity and robustness of DoEA’s environmental
review and approval process for two major projects that could be considered of national
importance; and it provides broader insights into Eskom’s capacity, commitment, and capability
to address environmental and social safeguards issues with respect to both the EIA process and
project implementation, since construction is well underway for both the Medupi and Kusile
power plant projects. Moreover, this focus on these two key projects is a particularly valuable
approach because both the safeguards work and the initial stages of construction have been
carried out in accordance with Eskom’s corporate practices prior to the decision by the GoSA to
seek Bank support for Eskom’s investment program.
8.
Although this SDR analytical work focuses on the Medupi and Kusile power plants as
representative examples to assess the borrower’s safeguards systems, it is important to note that
the Bank team also reviewed safeguards documents already disclosed on Eskom’s website for
additional Eskom investments that are expected to be financed in part by the Bank’s EISP. For
example, in preparing the SDR, the Bank team also reviewed the final EIRs prepared by Eskom
for the proposed Sere Wind Power Project (WPP) in Western Cape Province, the Concentrating
Solar Power (CSP) plant near Upington in Northern Cape Province, and the 67-km ErmeloMajuba rail line for coal transport in Mpumalanga Province, and found that the safeguards
documents for these proposed Eskom investments demonstrate comparable equivalence and
acceptability with respect to Environmental Assessment and treatment of Natural Habitats,
181
From 1994 through May 2009, DoEA was known as the Department of Environmental Affairs and Tourism (DEAT)
and reported to the Ministry of Environmental Affairs and Tourism, As part of a ministerial reorganization in May
2009, DoEA and the Department of Water Affairs (previous part of the Ministry of Water Affairs and Forestry) were
both placed under the authority of the newly designated Ministry of Water and Environmental Affairs and the
Department of Tourism became a separate Ministry of Tourism.
204
Physical Cultural Resources, and Involuntary Resettlement. The Bank team also will continue
reviewing the safeguards documents, such as Environmental Impact Reports (EIRs),
Environmental Management Plans (EMPs), or similar documents, prepared by Eskom for other
EISP components as they become available during project preparation, implementation, and
supervision.
9.
Basis for Selection of Pilot Country and Project. South Africa was selected as a pilot
country because it has an established legal and regulatory system and a favorable reputation for
effective implementation of its systems governing environmental assessment and protection of
natural habitats, protected areas, and physical cultural resources. This has already been
demonstrated by the SDR completed by the Bank for the recently approved Global Environment
Facility (GEF) project in support of the Development, Empowerment, and Conservation of the
iSimangaliso Wetland Park and Surrounding Region (iSimangaliso), which examined South
Africa’s legal framework for the same four safeguards that are triggered by the EISP, but with
reference to their application to an internationally protected wetlands area with substantial
autonomy from the mainstream of the South African administrative framework.
10.
The EISP was selected as a scaled up pilot project because the borrower, Eskom
Holdings Ltd., has demonstrated a substantial corporate commitment to fulfilling and going
“beyond compliance” with legal and regulatory requirements and embracing a sustainability
policy on both a corporate and project level. As described in detail below, Eskom subscribes to
the United Nations Global Compact,182 has obtained or is in the process of obtaining ISO 14000
certification for the Environmental Management System (EMS) for each of its operational units,
and seeks to align its projects and its practices with the requirements of the Equator Principles
(i.e., the International Finance Corporation’s Performance Standards) and with the Global
Reporting Initiative (GRI). Accordingly, there is reason to expect that Eskom’s systems are likely
to demonstrate strong equivalence with the World Bank safeguards as set forth in OP 4.00 Table
A1, and that Eskom’s investment projects making up the EISP would be implemented in an
acceptable manner with respect to Bank safeguard policies.
11.
SDR Methodology. This SDR for the EISP builds and expands on the results of the SDR
completed in March 2009 for the GEF-funded iSimangaliso project, which received Board
approval in December 2009. Although the iSimangaliso project involved a protected natural
habitat rather than an energy generation (and associated infrastructure) project, the SDR included
an Equivalence Analysis of the South African legal framework for Environmental Assessment,
Natural Habitats, Physical Cultural Resources, and Involuntary Resettlement. The March 2009
SDR concluded that the South African systems are fundamentally equivalent to the Objectives
and Operational Policies of OP 4.00 Table A1 with respect to the three environmental safeguard
policies, and partially equivalent with respect to Involuntary Resettlement in the context of its
application to management of a designated protected area.
12.
The Equivalence Analysis and Acceptability Assessment for the EISP were carried out by
a multidisciplinary team from the World Bank in collaboration with relevant officials and
technical staff members from Eskom, with cooperation from DoEA and the Department of Water
Affairs. The methodology included: desk review of legislation currently in force, supporting
regulations, and mandatory guidelines applicable to the electric power generation sector and
associated infrastructure; discussion with officials; and site visits to the Medupi and Kusile
construction sites, the Sere WPP site, the CSP site, and the 67-km Ermelo-Majuba rail line
servitude, by members of the Bank’s project team. The Bank team preparing the SDR consisted
entirely of senior level staff and included: an environmental lawyer, three environmental
specialists, a Senior Technical Advisor, and a social specialist.
182
www.unglobalcompact.org.
205
13.
The Equivalence Analysis included a detailed inventory of South African laws and
regulations relating to the four Bank environmental and social safeguard policies triggered by the
project, as identified below in the Equivalence Section of this report. These laws and regulations
are supported by Constitutional provisions, policies, and international agreements ratified by the
GoSA, all of which are included as relevant to the legal framework for the Equivalence Analysis.
An extensive literature review was also conducted tracing the development and evolution of
South African environmental law in both historical and comparative contexts. The analysis draws
careful distinctions between laws and regulations that are mandatory, as valid comparators to the
Operational Principles of OP 4.00 Table A1, and other documents having aspirational or guidance
value, which may inform the analysis and provide a basis for comparison with the Objectives of
OP 4.00 but cannot be considered conclusive evidence of equivalence with the mandatory
provisions of Bank safeguards. Based on this analysis each relevant provision of a borrower’s
system is characterized as having full, partial, or no equivalence to the corresponding Objective
or Operational Principle of OP 4.00 Table A1.
14.
The Acceptability Assessment applied the four-component methodology that has evolved
through the SDR process during the implementation of the UCS pilot program. These four
components include: institutional capacity; processes and procedures; outputs; and outcomes. To
assess relevant institutional capacity, the assessment drew on primary sources including external
and internal reports prepared by Eskom and DoEA. These reports provided valuable insights into
Eskom’s institutional capacity to: (a) conduct environmental assessment; (b) avoid, minimize,
mitigate and compensate for adverse environmental and social impacts resulting from the
construction and operation of thermal power plants and associated infrastructure, while
conserving natural habitat and physical cultural resources; and (c) conduct land acquisition and
related resettlement activities in accord with South African legal requirements and international
good practice as exemplified by Bank safeguard policies and associated guidance documents. The
SDR also examines the capacity of the DoEA to apply informed critical judgment to its review of
EIRs submitted by Eskom as demonstrated by its processing of the EIRs for the two power plants
proposed for support under the EISP, and by Eskom or other parties responsible for associated
infrastructure.
15.
To assess the effectiveness of implementing processes and procedures, the SDR reviewed
official procedural and guidance documents describing the appropriate conduct of the
environmental assessment and management process in South Africa. Attention was given to the
various stages of the environmental assessment process in South Africa including: the Scoping
Phase and EIR Phase, public consultation and disclosure, culminating in the Environmental
Authorization (formerly known as Record of Decision [ROD]) on the part of the Minister of
Environmental Affairs. Similar review was conducted with respect to the development and
approval of EMPs for the construction and operational phases of the two thermal power plant
projects. The EIRs and construction-stage EMPs were reviewed in light of the requirements for
environmental assessment under South African law and international good practice.
16.
With respect to outputs, the SDR critically reviewed: the findings of the EIRs and EMPs
for the Medupi and Kusile projects; the EIRs for the Sere WPP, the Upington CSP plant, and the
coal transport rail spur; and the RODs and other approvals issued by DoEA to date. The
Acceptability Assessment also reviewed the land acquisition and compensation process
undertaken by Eskom in connection with project development, and the outcomes of that process
with respect to compliance with South African law and the objectives and operational principles
of Bank policy with respect to Involuntary Resettlement.
17.
The methodology included stakeholder consultation workshops on the draft findings of
this SDR report as noted above. A summary of the workshops is included as an annex to this
report.
206
Summary of Equivalence Analysis
18.
The first step in the Equivalence Analysis is to identify the World Bank environmental
and social safeguard policies triggered by the project. The four environmental and social
safeguards triggered by the project include: Environmental Assessment (EA); Natural Habitats
(NH); Physical Cultural Resources (PCR); and Involuntary Resettlement (IR).
19.
This Equivalence Analysis finds that South Africa’s regulatory systems for all of the four
safeguards applicable to the project demonstrate sufficient equivalence so as to justify proceeding
to an Acceptability Assessment to determine if and on what basis the Bank can use South Africa’s
and Eskom’s systems in lieu of Bank safeguards to address the environmental and social
safeguard issues raised by the proposed project.
20.
The following findings apply to the four safeguards, respectively:

Environmental Assessment (EA). With respect to EA, the South African system is
deemed to be fully equivalent to the Objectives and Operational Principles of OP 4.00
Table A1. However one ambiguity in the language in the regulatory framework
required additional clarification during the preparation of the SDR:
o
It is not clear from the regulations that the assessment of alternatives is
required to assess their relative feasibility with respect to all of the feasibility
criteria cited in OP 4.00 Table A1. It appears from the South African
regulations that the proponent has the option to include those alternatives
deemed “feasible and reasonable” and compare the advantages and
disadvantages of such alternatives for the environment and the community.
But it does not explicitly require the EIR to justify alternatives considered on
the basis of comparative capital and recurrent costs, and institutional, training
and monitoring requirements, which are among the criteria noted in OP 4.00
Table A1 as among the criteria to be uniformly considered. DoEA (thenDEAT) published guidance on criteria to be included in alternatives
assessment in 2004 (Integrated Environmental Management Information
Series, Series 11: Criteria for Determining Alternatives in EIA), which
recognizes that the range of criteria must be appropriate to the type of project
subject to the EIA process.
As noted later in this report, Eskom’s policy and practice is to address
alternatives assessment at both the strategic and project-specific levels.
Although South African regulations do not explicitly require consideration of
capital and recurrent costs, and institutional training and monitoring
requirements, among the key factors for all projects, Eskom does so at both
levels of analyses. Thus, any ambiguity is resolved with respect to Eskom’s
approach to alternatives analyses.

Natural Habitats (NH). With respect to NH, the South African system is deemed to
be fully equivalent to the Objectives and Operational Principles of OP 4.00 Table A1.
However one ambiguity in the regulatory framework required additional clarification
during the preparation of the SDR:
o
South African legislation appears to lack a conservation offset provision for
non-critical natural habitat. South Africa recognizes that as the development
footprint increases, there will be unavoidable net loss of non-critical habitat,
but through the Environmental Authorization (formerly ROD) process,
biodiversity offsets can be required on a case-by-case basis.
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As noted later in this report, Eskom, through its partnerships with South
African conservation organizations, has supported conservation offsets for
projects that convert natural habitat, even though South African legislation
does not appear to require such practice.

Physical Cultural Resources (PCR). With respect to PCR, the South African system
is deemed to be fully equivalent to the Objectives and Operational Principles of OP
4.00 Table A1. However a few ambiguities in the regulatory framework required
additional clarification during the preparation of the SDR:
o
The extent of participation and obligations of communities in the process of
cultural heritage assessment and conservation remains within the scope of the
EIA process, as specified by the National Heritage Resources Act, but are not
as explicit as stated in OP 4.00 Table A1.
o
It is not clear how the legislative framework deals with “chance finds.” A
standard condition is included in all Environmental Authorizations (formerly
RODs) stipulating how “chance finds” must be dealt with during the
construction and operational phase, but the legal basis for this requirement is
not explicit in the regulations.
Although South African regulations do not require it, Eskom implements its
policy of extensive local stakeholder consultation regarding cultural
resources, along with its standard protocol requiring that “chance finds” be
reported immediately to the South African Heritage Resources Agency
(SAHRA) and that construction is halted at the discovery until qualified
experts are consulted.

Involuntary Resettlement (IR). With respect to IR, the South African system is found
to be fully equivalent to the Objectives and Operational Principles of OP 4.00 Table
A1 for all but the following Operational Principles:
o
Rights of access to natural resources and biodiversity of protected areas
(however, as there are no protected areas affected by the project, this gap in
equivalence is not relevant to the conclusion of this SDR);
o
Disclosure of draft resettlement plans in a timely manner to the public at
large is not clearly spelled out in Eskom guidelines, although it is a
requirement with respect to directly affected parties under various Acts
related to the National Environmental Management Act (NEMA) and
legislation concerning land acquisition.
It should be mentioned, however, that Eskom has developed a practice to conduct
assessment to confirm whether the objectives of resettlement have been achieved
upon completion of the project, taking into account the baseline conditions and the
results of resettlement monitoring. It also should be noted that the South African
legislation regarding resettlement requires extensive consultation and disclosure with
directly affected people, i.e., those who are to be resettled, and provides for benefits
and livelihood restoration in a manner consistent with the Bank’s safeguard policy.
Therefore, for the EISP, the key gaps appear to be the absence of a requirement for a
stand-alone, formal Resettlement Action Plan that is disclosed to a broad audience of
interested parties, and a formal mechanism for a completion audit.
Summary of Acceptability Assessment
21.
The purpose of the Acceptability Assessment is to confirm that the implementation
practices, track record, and institutional capacity of Eskom, and the South African regulatory
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institutions that will be involved in addressing environmental and social safeguard issues in the
proposed Bank-supported EISP, fulfill the requirements of OP 4.00 Table A1. The Acceptability
Assessment examined four criteria: institutional capacity; processes and procedures; outputs; and
outcomes of the borrower’s systems for EA, NH, PCR, and IR.
Institutional Capacity
22.
The institutions responsible for implementing the four environmental and social
safeguards applicable to the project include, in the first instance the borrower, Eskom, as well as
DoEA (under the authority of the Ministry of Environmental Affairs and Tourism until May
2009, and now under the authority of the Ministry of Water and Environmental Affairs with
respect to environmental impact assessment and air and water quality management); Department
of Water Affairs (DWA, formerly the Department of Water Affairs and Forestry), which enforces
regulations governing the supply and use of water; the Department of Land Affairs, under the
Ministry of Agriculture and Land Affairs with respect to land acquisition; the South African
Heritage Resource Agency (SAHRA), which provides the expertise in South Africa to develop
and implement policies and practices regarding protection and management of cultural resources;
and provincial and municipal authorities with respect to many of these same authorizations.
23.
Eskom. Eskom is South Africa’s national, vertically integrated electricity utility, and is
wholly owned by the GoSA through the Department of Public Enterprises. Eskom’s current
structure is defined by the Eskom Conversion Act of 2001. The utility employs about 35,500
employees (reduced from about 66,000 over the past two decades). Eskom operates its business
through a number of divisions and subsidiary companies. Eskom’s core business as a utility is
carried out by the three divisions under the heading Eskom Core Business and is described below,
followed by a brief description of the operations of the key subsidiaries.
24.
At the corporate level, environmental and social governance within Eskom begins at the
level of the Chief Executive Officer (CEO) and is overseen by the Executive Directors, who are
full time employees of Eskom, and by the authority delegated to Board Committees, including the
Executive Management Committee and the Sustainability and Safety Subcommittee. The latter is
comprised of four independent non-Executive Directors, along with the CEO and two Board
Members, and guides corporate strategy on sustainability, occupational health and safety, and
environmental matters in line with Eskom’s safety, health and environment policy, the NEMA,
and the Occupational Health and Safety Act of 1993.
25.
Within the management structure of Eskom, each line division (Generation,
Transmission, or Distribution) is individually responsible for carrying out the EIA process,
producing EIRs as required by South African regulations, and implementing the environmental
management and monitoring activities associated with its line of business. To undertake these
tasks Eskom has more than 100 environmental and social specialists located in their headquarters
office and various field operations.
26.
Eskom has a comprehensive “triple bottom line” approach to the management of
environmental, health, and safety issues as part of its corporate commitment to sustainability. As
one of the charter members of the United Nations Global Compact, Eskom is committed to
uphold the ten principles of the Compact, which include inter alia protection of the environment,
labor standards, human rights, and anti-corruption. Eskom’s sustainability performance in 2006
met the requirement for inclusion in the Johannesburg Stock Exchange Socially Responsible
Investment Index. Eskom has a systematic audit process in place to ensure that any noncompliance with South African legal requirements is identified, reported, and investigated, and
that corrective and preventive measures are implemented.
27.
The one weakness at the Eskom corporate level that was identified in this SDR is the
need, publicly acknowledged by Eskom, to pay greater attention to occupational health and
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safety, as indicated by a recent record, which Eskom itself characterizes as “unsatisfactory,” of
traffic-related fatalities and injuries and incidents of electrocution resulting from accidental or
unauthorized contact with energized lines or electrical equipment. Accordingly Eskom proposed
to enhance its “…focus [on] safety training and awareness, skills, competency, supervision and
operational discipline…,” and has put in place a procedure to investigate all fatalities promptly
and share lessons learned from case studies. In addition, Eskom engaged the services of an
international specialist to evaluate its electrical safety as well as behavioral safety programs.
Changes were made to the Eskom training materials to incorporate some of the recommendations
made. With respect to community safety, campaigns to improve public awareness were rolled out
in various media and included school visits and the handout of safety materials.
28.
DoEA. Established in 1994, as the Department of Environmental Affairs and Tourism,
DoEA is an independent Department of the GoSA responsible for protecting, conserving, and
improving the environment and natural resources. It now reports to the Minister of Water and
Environmental Affairs, who is a member of the Cabinet and is appointed by the President from
among members of the National Assembly.
29.
DoEA management and staff have high levels of specialized training in all key areas of
environmental assessment and management. In particular, the Air Quality Directorate at DoEA
has been fully engaged in developing and implementing ambient air and emissions standards that
are aligned with international good practice as defined by the World Bank, the European Union,
and the United States Environmental Protection Agency.
Processes and Procedure for Environmental Assessment and Management for Coal-Fired
Thermal Power Plants and Associated Infrastructure
30.
South Africa began undertaking EIA in an ad hoc manner during the 1980s, and a
voluntary EIA procedure was integrated into the Environmental Conservation Act of 1989
(ECA), since largely superseded by the National Environmental Management Act (NEMA).
Requirements for EIA were introduced on a sectoral basis in the Minerals Act of 1991 (Sections
38 and 39(5)). These requirements were generalized by the EIA Regulations of September 5,
1997, which mandated a process including screening, scoping, public participation,
environmental reports, review, and decision. (For purposes of clarity, it should be noted that the
current South African regulations refer to an EIA process, which produces an EIR, and this
terminology is used in this SDR).
31.
Following an extensive process of expert review and public consultation and discussion,
substantially revised EIA Regulations were issued in 2006. The new regulations resulted in a
more coherent process with respect to application of EIA including: (a) EIA scoping, (b)
decision-making procedures, (c) roles, (d) responsibilities and compliance, (e) public
participation, and (f) appeal process.
32.
In November 2008, DoEA (then DEAT) commissioned and issued a draft review of the
previous ten years of EIA practice in South Africa. The draft report was conducted by
independent consultants. The main findings of the report are that: (a) the overall effectiveness of
EIA process in South Africa in meeting requirements of ECA and then NEMA was deemed
moderately effective but with room for improvement; (b) overall there was a significant
improvement in effectiveness and efficiency of EIA in moving from the ECA regulations to the
NEMA regulations; (c) public participation in EIA is effective; (d) the cumulative (combined)
impacts aspect is generally not considered effective and there is significant room for
improvement; (e) the EIA process in South Africa is implemented relatively efficiently in terms
of the average time it takes to produce and evaluate EIAs; (f) monitoring and enforcement in
environmental management is one area where the current EIA system is not effective or efficient;
and (g) a more strategic approach to environmental impact management is required and there is a
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definite need to move away from an “EIA only” system to one based on integrated environmental
management.
33.
South Africa’s legal and regulatory framework for management of ambient air quality is
based on World Health Organization standards, and is therefore closely aligned with those used
by the World Bank Group (WBG) as specified in the WBG General Environmental, Health and
Safety Guidelines (EHSG) issued in April 2007. With respect to levels of emissions from thermal
power plants, the proposed South African regulatory approach to emissions standards for new
plants is generally comparable to the WBG EHSG for Thermal Power issued in December 2008
in that it distinguishes between new and existing plants and sets more stringent requirements for
plants that discharge emissions to a degraded airshed. (see Annex 4 of the SDR).
34.
Permitting is a key output of the EIA process in South Africa. With respect to the air
quality impacts of electrical generating facilities, the principal authorization is the Atmospheric
Emission License (AEL). The granting of an AEL must be preceded by the issuance of a ROD,
now referred to as an Environmental Authorization, for an EIA application, which, for listed
activities (including thermal power plants with more than 70 MW heat output) is required to be
accompanied by an Air Quality Impact Assessment Study prepared by qualified specialists.
Metropolitan and district municipalities are charged with implementing the atmospheric licensing
system per Section 36 of the Air Quality Act of 2004 (AQA), subject to alternative arrangements
in which a provincial organ of state may be designated as the issuing authority. The contents of an
AEL must include the maximum allowed amount, volume, and emission rate or concentration of
pollutants that may discharged into the atmosphere under normal working conditions and during
start-up, maintenance, and shut-down conditions.
35.
Compliance monitoring and enforcement requirements for ambient air quality and
emissions from electricity generating facilities are set forth in the Atmospheric Pollution
Prevention Act of 1965 (APPA) which is being phased out under the terms of the 2004 AQA.
Standards issued under the AQA also set forth reference methods and siting criteria for sampling
of priority air pollutants associated with electricity generation facilities including particulate
matter (PM10), sulfur dioxide (SO2), nitrogen oxides (NOx), and carbon monoxide (CO) as well as
ozone, lead, and benzene.
36.
As part of the National Framework for Air Quality Management in South Africa
(National Framework), and in implementation of mandatory provisions of the AQA, an extensive
network of ambient air quality stations has been established, owned and operated by a variety of
organizations. South African National Standards (SANS) for ambient air quality monitoring have
been established.
37.
However, the AQA itself makes no provision for the enforcement of its own provisions;
rather, enforcement provisions are located in NEMA as framework legislation, where provision is
made for the statutory designation of Environmental Management Inspectors (EMIs) to monitor
compliance with and enforce AQA. NEMA grants EMIs (acting within their designation and
mandate) extremely wide powers, including powers of inspection, investigation, administrative
and enforcement actions. The first EMIs were designated by the Minister of Environmental
Affairs and Tourism in June 2006 and there were 903 trained and designated EMIs reached as of
March 31, 2008.
Processes and Procedures for Management of Social Impacts from Thermal Power Plants and
Associated Infrastructure
38.
Eskom seeks to avoid land expropriation wherever possible and includes the potential
need for expropriation, resettlement, compensation and rehabilitation among the criteria used for
alternative site assessment. When resettlement is unavoidable, all displaced people are effectively
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consulted and compensated; support and other benefits are provided in the relocation process,
including livelihood restoration (“rehabilitation”) as mandated by GoSA law.
39.
Eskom provides security of tenure to resettled parties and helps register deeds of
ownership.
40.
Replacement accommodation is based on South African Bureau of Standards
requirements for housing, which require minimum brick, mortar and tile structures with running
potable water and proper sanitation. Where cost-effective, Eskom also seeks to provide electricity
to replacement structures. Eskom’s expenditure in these transactions is strictly controlled by the
Public Finance Management Act; however, it is Eskom’s policy to ensure that resettled parties are
better off than prior to resettlement. Eskom seeks to maximize employment of displaced persons
in whatever jobs may be available on project sites. However, these are typically unskilled
construction jobs of limited duration.
41.
Where in-kind resettlement opportunities are not available, Eskom provides cash
compensation based on an independent valuation using open market selling trends of similar land
based on registered sales over a period between three months and three years. In cases where the
land owner disagrees with the compensation offered, the owner is entitled to hire a valuer of his
or her own choosing, with the final offer typically reflecting the difference between the two
valuations.
42.
Although Eskom does not prepare formal publicly-disclosed resettlement plans, Eskom
does undertake independent social assessment and develops internal plans for resettlement with
timelines and commitments. The plan is treated as a living document that is updated as required
on an ongoing basis. All negotiated outcomes are documented as formalized agreements and the
entire resettlement process is documented and filed by Eskom. The implementation phase of the
contractual resettlement plan is monitored and evaluated and is subject to amendment by mutual
agreement of the parties.
Public Consultation and Disclosure in the EIA and Land Acquisition and Resettlement
Processes
43.
In examining the EIA process for both the Medupi and Kusile projects, the Bank team
determined that Interested and Affected Parties (I&APs) were informed about the projects and
consulted at various stages of the EIA process. During the Scoping Phase public participation was
comprehensive and included advertising in national, regional, and local newspapers, subsequent
notifications in regional and local newspapers, and the dissemination of a non-technical
Background Information Document (BID) in English, Afrikaans, and local languages, which was
updated on various occasions to take account of the evolution of the project. Public fora were
held at diverse venues in each area, organized and facilitated by an independent consultant.
Following the issuance of the Draft EIR reports, both on the internet and in hard copy at local
public libraries and municipal offices, a second round of local public consultations took place.
44.
The main issues raised by stakeholders for the Medupi and Kusile projects concerned
increases in air and noise pollution and the consequent potential impacts on public health. The
issues raised and the responses by Eskom and government authorities to public comments and
questions is thoroughly documented in minutes from the public consultations and summarized
thematically in two “Issues Trails” documents prepared by the independent consultant.
Stakeholders are also encouraged and often comment not only on the substance of the EIR but
also on the disclosure and consultation process itself. The public consultation process is continued
during construction, and will continue throughout project implementation with the assignment of
Environmental Control Officers and the constitution of Environmental Monitoring Committees
that include local stakeholder representatives.
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Outputs: EIA Process and EIR Content for Medupi and Kusile
45.
The EIA process for the Medupi and Kusile plants, as well as associated transmission
lines and most of the investments under consideration for the EISP, has been thoroughly
documented, and the project-specific EIRs of projects that Eskom proposes to undertake are
disclosed (and remain available) on Eskom’s website.183 The EIA processes and content of the
EIRs for the two thermal power plants now under construction conform fully to the regulatory
requirements in effect at the time that the applications to commence the EIA process were
approved, i.e., the EIA Regulations issued in 1997 under the authority of the ECA of 1989.
However, the EIA process and EIR content for both projects was strongly influenced by and is
essentially consistent with the EIA Regulations that became effective in July 2006, although they
are not legally applicable to the Medupi and Kusile projects. This is because the EIA process for
both projects began at a time when the draft new regulations were already out for public
comment; therefore, Eskom chose, and instructed its consultants, to conform with the proposed
new regulations as well. As noted in the Equivalence section of this report, the 2006 EIA
Regulations are nearly fully equivalent to the Objectives and Operational Principles of OP 4.00
Table A1 with the exception of an ambiguity in the regulations regarding whether capital and
recurrent costs, and training and monitoring requirements are among the criteria to be considered
as part of the alternatives assessment. However, as would be expected, these criteria were fully
addressed in the strategic planning and project-specific EIA process for the two plants as per
Eskom’s corporate practice.
46.
An independent assessment of the EIA process and resulting EIRs commissioned by
Eskom concluded that both the EIA process and the content of the EIRs were consistent with the
requirements of the Equator Principles, which are based on the International Finance Corporation
(IFC) Performance Standards and which also make reference to the WBG Thermal Power
Guidelines issued under the 1998 PPAH and as revised in December 2008.
47.
The Bank’s own review of the EIRs indicated that both are consistent with international
good practice and with the Objectives and Operational Principles of OP 4.00 Table A1 with
respect to EA, notwithstanding the minor ambiguity in the South African legal framework as
noted in the Equivalence Analysis.
48.
To date final EMPs have been prepared and approved by DoEA for the construction
phase of the Medupi and Kusile projects, and a draft EMP has been prepared for the operational
phase of Medupi. Based on a review of these documents it may be concluded that the EMPs
satisfy South African regulatory requirements and are consistent with Bank-recommended
practice for EMP.
49.
The EIRs for the two plants were approved by DoEA in publicly disclosed RODs issued
in September 2006 for Medupi and in June 2007 for Kusile. The RODs include a long list of
statutory and regulatory requirements reflecting site-specific projected impacts as documented in
the EIRs. These impacts relate primarily to air emissions and ambient air impacts; liquid effluent
control; management of ash and other solid wastes; and hazard assessment. The RODs require
that Eskom implement detailed monitoring and reporting protocols, and that Eskom appoint
independent Environmental Control Officers (having dual reporting to Eskom and DoEA) and
establish Environmental Monitoring Committees including local stakeholder representatives. The
RODs demonstrate that DoEA has the capacity and commitment to independently assess and
identify conditions that should be imposed on projects on a case-by-case basis.
50.
It should be noted that the RODs issued by DoEA provide approval based on the
satisfactory conclusion of the EIA process and conditions attached to project implementation. As
noted in the RODs for the Medupi and Kusile projects, Eskom must still obtain individual
183
www.eskom.co.za/eia.
213
permits, including an AEL from the Chief Air Pollution Control Officer (DoEA) as per the AQA,
a Water Use License, and licenses for waste disposal, among others. Issuance of some of these
licenses, especially for the operational phase, is still pending. RODs for some of the other EISP
components and associated transmission lines are publicly disclosed and available on DoEA’s
website (http://www.environment.gov.za/).
Projected Outcomes: Environment
51.
The major potential environmental impacts of both the Medupi and Kusile projects relate
to the impact of emissions on local air quality and human health, in particular with respect to the
major pollutant, SO2. As existing ambient air quality conditions and water resources differ among
the two sites, so does the timing of the proposed mitigation measures as presented in the EIR and
required by the ROD.
52.
The designated airshed at Medupi, which corresponds to the Waterberg District
Municipality, is not yet considered degraded with respect to ambient air quality. However,
ambient conditions in the airshed are expected to deteriorate in the future. Accordingly, DoEA
intends to propose that the Minister declare the Waterberg airshed as a National Priority Area for
Air Quality and this declaration is likely to be issued sometime within the next year. Such a
declaration would provide DoEA with additional authority to require designated sources of
emission, including Eskom, to take specified measures to reduce emissions such that ambient
conditions are maintained at acceptable levels. In addition, DoEA has proposed emission
limitations for new and existing thermal power plants that will come into effect along with certain
provisions of the AQA on April 1, 2010. Under these provisions as currently proposed, Medupi
would be required to meet the limitations for existing plants within five years of commencing
operations, and the much more stringent limitations applicable to new plants within an additional
three to five years.
53.
These ambient and emission limitations will oblige Eskom, to take unspecified measures
to substantially reduce its sulfur dioxide (SO2) emissions from the levels that would result from
direct unmitigated combustion of coal to levels below the applicable emission limits and to take
other actions, as necessary as specified in its ROD, (and to be further specified in its AEL) in
order to further reduce its contribution to ambient conditions. Flue Gas Desulfurization (FGD)
technology is the only means of achieving significant reductions in SO2 emissions from a given
coal feedstock; accordingly, Eskom’s Board of Directors has approved installation of FGD and
Eskom has designed and is constructing the Medupi plant to be “FGD-ready,” with sufficient
infrastructure in place to accommodate installation of wet-FGD technology when it becomes
necessary, and technically and operationally feasible to do so. Eskom’s staged approach to FGD
is consistent with its environmental authorization (the ROD).
54.
Although wet-FGD is the most efficient technology for reduction of SO2 emissions,
Eskom faces a potential significant constraint in that wet-FGD is highly water intensive and local
sources of water are insufficient to operate the plant at full capacity, even without FGD.
Accordingly, Eskom is seeking from DWA an allocation of water from supplemental water
sources, sufficient not only to operate the plant at full capacity, but to operate FGD when
necessary. This allocation is dependent on the availability of water from the Mokolo and
Crocodile Water Augmentation Project (MCWAP) that is being developed by DWA to supply
supplemental water to priority users, including Eskom, in the Waterberg District Municipality and
elsewhere in Limpopo Province. This water supply is not expected to become available until 2014
at the earliest by which time all six units at Medupi are expected to be operational.
55.
As noted above, initially, and for five years of operations, Eskom will be required to
operate Medupi in compliance with the proposed emissions standards for existing plants. Based
on the data from the EIR, it would appear that Medupi should be able to meet these standards in
the absence of FGD. However, once the standard for new plants become applicable to Medupi, in
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about 2019, Eskom will need to have FGD installed at Medupi. Accordingly, Eskom is planning
to undertake FGD installation from 2018-2021, as part of its scheduled operational maintenance
program, during which each power block is taken off-line for routine maintenance beginning after
six years of operation. Although progress on the project to supply the required amount of water is
on schedule, the Bank has, nevertheless, requested evidence from the Department of Water
Affairs, committing to timely water supply to Eskom. Furthermore, in the event that sufficient
water is not available (or allocated to Eskom) from the MCWAP, the Bank will recommend that
Eskom proactively investigate the feasibility of using a less water intensive dry-FGD technology
prior to commencing full operations.
56.
It should be noted that with either wet- or dry-FGD technology installed it is expected
that Medupi would be able to operate in compliance not only with the proposed South African
limitations for new plants, but with the equally stringent World Bank Group Environment, Health
and Safety Guidelines for Thermal Power plants issued in December 2008.
57.
In contrast to Medupi, Kusile is located in an airshed that is already considered degraded
with respect to particulates, but is adequately supplied with sufficient water to operate a wet-FGD
system from the commencement of operations. Therefore the ROD for Kusile requires that the
FGD system be fully operational at commissioning. Accordingly, Kusile will comply from the
outset with international good practice as recommended in the Bank’s 2008 EHSG for Thermal
Power Plants, as well as with the forthcoming national regulations for new sources. Both plants
are to be equipped with fabric (baghouse) filters to control emissions of particulates, and lowNOx burners to reduce emissions of NOx to levels consistent with proposed South African
regulatory requirements and international good practice as recommended in the Bank’s 2008
EHSG for Thermal Power Plants.
58.
With respect to wastewater control, both Medupi and Kusile are designed as Zero
Effluent Discharge facilities during operations, with all process and wastewater to be recycled.
Solid waste, in the form of coal ash, will be disposed of in engineered ash storage facilities that
will be lined and equipped with leachate detection and collection capacity. Ash disposal will
occur with the minimum amount of water necessary to prevent dust formation; once deposited,
the ash is quickly covered with topsoil for purposes of revegetation.
Projected Outcomes: Social Impacts
59.
The social impacts from both Medupi and Kusile are of a moderate scale. As explained
below, there was no need to conduct a full Resettlement Action Plan or Framework under OP
4.00 Table A1 (or OP 4.12) for the Medupi project, and resettlement was relatively small scale
for the Kusile project. In neither case has expropriation been required nor are there any
outstanding restitution claims on lands to be acquired for the projects. In both cases land has been
acquired by Eskom through voluntary willing buyer-willing seller transactions at realistic market
based prices wherein land was acquired from local farmers. Social assessment and public
outreach were undertaken to fully identify individuals and households, including neighboring
farms and farm laborers, whose livelihoods might be affected by the land acquisition and other
project activities.
60.
For the construction and operation of Medupi two game farms were purchased by Eskom.
At one of the game farms there was one full-time worker residing on the farm at the time of
purchase, and it was agreed that the farm worker will continue to be in the owner’s employ and
be relocated at the owner’s expense to one of his other properties. No laborers or any other
occupiers resided on the other farm at the time of purchase, and therefore no relocations were
required with respect to that property.
61.
At Kusile, social assessment indicated the presence of 18 family units of farm laborers
requiring resettlement. To implement the resettlement, Eskom engaged the services of a
215
specialized contractor, and, through a process of extensive consultation with the directly affected
people, provided the families with several resettlement options on neighboring farms, some
owned by Eskom, or on other land leased from other farmers for the purpose of resettlement. The
families that opted to resettle on the Eskom-owned farms were provided with permanent homes
with individual fencing, running water and sanitation, vegetable gardens, and a playground for
children. Eskom assisted the project-affected peoples in establishing a Communal Property
Association that would acquire ownership of the properties in the names of the family units. For
those families who elected through the consultation process to be resettled on other properties,
Eskom arranged to have existing structures rehabilitated or constructed new structures where
existing structures were not of sufficient quality.
62.
For the transmission lines that will be built as associated facilities for the EISP, Eskom
follows its corporate practice of initially identifying, through the EIA process, corridors that
avoid or minimize the need for relocation of households or farm structures, and subsequent
refinement of the location of the right-of-way and tower locations within the preferred corridor to
further reduce the need for physical displacement of people or structures, and avoid or minimize
adverse effects on livelihoods or economic activities. Land valuation is required as part of the
route selection process to determine appropriate compensation for acquisition of right-of-way for
construction and maintenance.
Summary of Gaps and Proposed Gap-Filling Measures
63.
OP 4.00 requires that prior to piloting a project under a borrower’s environmental or
social safeguard system, the Bank and the borrower reach agreement on a time-bound Action
Plan to address gaps in Equivalence and Acceptability that have been identified in the SDR. At
the draft stage of the SDR the Bank discloses the gaps that have been identified for further
discussion with the borrower and other stakeholders including local stakeholders in the proposed
project. For the EISP, the borrower is Eskom. The gap analysis begins with the South African
laws and regulations as the regulatory framework with which Eskom must comply, but the final
analysis of required gap-filling measures focuses on the consistency of Eskom’s policies,
procedures, and practices for its projects with respect to OP 4.00 Table A1.
64.
Equivalence. With respect to the SDR process conducted to date, the Bank has identified
a few minor ambiguities or gaps in South Africa’s legal framework with respect to the four Bank
safeguard policies triggered by the EISP. However, it would appear from the analysis of Eskom’s
policies and procedures that all of these gaps in the legal framework applicable to environmental
safeguards are fully addressed and internalized in Eskom’s policies and practices, with the
exception of preparation of a stand-alone Resettlement Action Plan and its disclosure to a broad
public audience.
65.
With respect to EA, Eskom’s policy is to address alternatives assessment at both the
strategic and project-specific levels, irrespective of any residual ambiguities in South Africa’s
legal framework for the types of factors to consider in alternative analysis as part of the EIA
process. Therefore, although South Africa requires alternatives analysis to include capital and
recurrent costs, or institutional training and monitoring requirements as a matter of good practice,
rather than as a regulatory requirement, Eskom does so as a standard operating procedure at both
strategic and operational levels of analysis.
66.
With respect to NH, Eskom, through its partnerships with South African conservation
organizations, has supported conservation offsets for projects that convert natural habitat,
although South African legislation does not, as matter of policy require such offsets. In any case,
neither the Medupi nor Kusile projects will impact significant areas of high quality natural habitat
to an extent that such an offset would be necessary or appropriate.
216
67.
With respect to PCR, Eskom’s existing policy of extensive local stakeholder consultation
regarding cultural sites and artifacts along with its standard protocol requiring that “chance finds”
be reported to the South African Heritage Resources Agency (SAHRA) obviates a need for gapfilling at the institutional level. A review of project construction to date demonstrates that
Eskom’s approach to “chance finds” has been effectively implemented by Eskom’s construction
contractors, even though South African regulations do not require a formal protocol to address
chance finds.
68.
It is only with respect to IR that South Africa appears to lack a legal mechanism, and
Eskom an administrative mechanism, to require the preparation of publicly-disclosed, stand-alone
resettlement plans or frameworks, or to publicly disclose its evaluation of the success of
resettlement and rehabilitation activities. Accordingly, the Bank proposes to encourage Eskom to
introduce such an administrative mechanism as corporate practice. Eskom has already disclosed
on its website its corporate resettlement policy,184 which summarizes its corporate policy and
practice with respect to land acquisition, resettlement, and rehabilitation (livelihood restoration)
and a Resettlement Policy Framework specific to Components 2 and 3 of EISP.185 Audits will
also be required for any resettlement already carried out for EISP components. For any EISP
components for which resettlement is needed but has not yet occurred, the Bank will require and
Eskom has agreed to disclose its draft resettlement plans for those components.
69.
Acceptability. A detailed review of Eskom’s policies and procedures with respect to the
four triggered safeguard policies as implemented on a corporate level, and as demonstrated by the
planning and implementation of the Medupi and Kusile projects to date, indicates a high level of
consistency with international good practice as exemplified by international standards of
corporate environmental and social management, such as the United Nations Global Compact,
IFC Performance Standards, the Equator Principles, and relevant WBG EHSG. There are,
however, two outstanding issues where there are potential gaps in Eskom’s performance with
respect to the expected outcomes of the Medupi and Kusile projects.
70.
With respect to SO2 emissions and ambient impacts on air quality and human health, the
Bank, due to short tenure of its proposed loan agreement, relative to the regulatory timetable for
Medupi’s compliance with the proposed South African regulations, will seek agreement with
Eskom to commit to timely installation of FGD in all six units at Medupi as soon as it is
technically and operationally feasible to do so, and to seek Eskom’s agreement to provide to the
Bank in mid 2013 a report satisfactory to the Bank that provides a plan and schedule for timely
installation of SO2 emissions abatement measures. This may include an independent feasibility
analysis of alternative control technologies in the event that sufficient water is not available or
allocated to enable Eskom to operate the wet-FGD units. Given that Eskom’s compliance with
South African emissions requirements can be expected to result from the implementation of the
South Africa’s existing and proposed regulatory system, without Bank intervention, and the
supplemental agreements reached between the Bank and Eskom are for the sole benefit of the
Bank as a medium-term lender, these agreements need not be considered as “gap-filling
measures” as this term is used in this SDR. However, any subsequent changes in South Africa’s
regulatory requirements or actions, which would bring this compliance into question, would
trigger Bank remedies per OP 4.00.186
184
“Procedure for the Involuntary Resettlement of Legal and Illegal Occupants on or from Eskom-Procured Land;”
(July 2009). http://www.eskom.co.za/content/20091009091904201.pdf
185
“Status and Process of Land Acquisition and Resettlement for Eskom’s Concentrating Solar Plant (CSP), Wind
Energy
Facility,
Majuba
Rail
and
Transmission
Projects”
(October
2009).
http://www.eskom.co.za/content/RelocationResettl_Final.pdf
186
OP 4.00, para. 6, “Changes in Borrower Systems and Bank Remedies. If, during project implementation, there are
changes in applicable legislation, regulations, rules or procedures, the Bank assesses the effect of those changes and
discusses them with the borrower. If, in the judgment of the Bank, the changes reflect a further improvement in the
217
71.
With respect to IR, Eskom staff has acknowledged the benefits of conducting
independent retrospective monitoring of the social and economic impacts of any involuntary
resettlement associated with its projects. For EISP components where resettlement has already
occurred, the Bank will require that Eskom conduct and publish an audit of the resettlement based
on Terms of Reference to be agreed by the Bank. For any EISP components for which
resettlement is needed but has not yet occurred, the Bank will require Eskom to disclose its draft
resettlement plans for those components. To begin addressing this identified gap between Bank
policy and Eskom’s practice, Eskom prepared and disclosed on its website a Resettlement Policy
Framework, which explains its corporate approach to resettlement and land acquisition.
country systems, and if the borrower so requests, the Bank may agree to revise the legal framework applicable to the
operation to reflect these improvements, and to amend the legal agreement as necessary. Management documents,
explains, and justifies any changes to such framework, and submits them for Board approval (normally on an absence
of objection basis). If the country system is changed in a manner inconsistent with the legal framework agreed with the
Bank, the Bank’s contractual remedies apply.”
218
Annex 12: Project Preparation and Processing
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Planned
09/21/09
09/21/09
09/21/09
02/03/10
02/16/10
03/23/10
04/20/10
01/1/13
10/30/15
PCN review (at OC level)
Initial PID to PIC
Initial ISDS to PIC
Appraisal
Negotiations
Board
Planned date of effectiveness
Planned date of mid-term review
Planned closing date
Actual
09/21/09
11/11/09
11/11/09
02/01/10
03/16/10
04/08/10
-
Key institutions responsible for preparation of the project include: Eskom Holdings, National Treasury,
Department of Minerals & Energy, Department of Public Enterprises, and Department of Water &
Environment.
Bank staff and consultants who worked on the project included:
Name
Reynold Duncan
Pankaj Gupta
Suman Babbar
Sandeep Mahajan
Elzbieta Sieminska
V.S. Krishnakumar
Mark Walker
Edith Ruguru Mwenda
Mohammed Bekhechi
Charles Di Leva
Juan Gaviria
Pierre Pozzo de Borgo
Harvey Himberg
Harvey van Veldhuizen
Thomas Walton
Frederick Edmund Brusberg
Mudassar Imran
Mustafa Zakir Hussain
Andrey Gurevich
Ahmad Slaibi
Heather B. Worley
Sarwat Hussain
Karan Capoor
Gert Van Der Linde
Modupe Adebowale
Miguel Oliviera
Andrew Asibey
Armando Araujo
Aman Sachdeva
Peter M. Meier
Richard Bullock
Victor Loksha
Susan Shilling
Jemima Harlley
Rita Ahiboh
Title
Lead Energy Specialist/Co-Task Team Leader
Lead Financial Specialist/Co-Task Team Leader
Consultant and Project Finance Advisor
Lead Economist
Lead Procurement Specialist
Regional Procurement Manager
Chief Counsel, Africa Region
Sr. Counsel
Lead Counsel, Environment
Chief Counsel, Environment
Sector Leader, Sustainable Development
Lead Transport Specialist
Consultant, Environmental Specialist
Lead Environmental Specialist
Consultant, Environmental Specialist
Lead Social Development Specialist
Sr. Economist
Sr. Infrastructure Finance Specialist
Financial Analyst
Young Professional/Economist
Communication Officer
Sr. Communications Officer
Sr. Financial Specialist
Lead Financial Management Specialist
Senior Financial Management Specialist
Finance Officer
Senior Monitoring and Evaluation Specialist
Consultant/Procurement Advisor
Consultant/Financial Analyst
Consultant/Power Economics
Consultant/Railway Economics
Consultant/CTF Financing
Program Assistant
Program Assistant
Program Assistant
219
Unit
AFTEG
AFTEG
AFTEG
AFTP1
AFTPC
AFRPC
LEGAF
LEGAF
LEGEN
LEGEN
AFTTR
AFTTR
OPCQC
OPCQC
AFTEN
SARDE
AFTEG
FEUFG
AFTEG
AFTEG
AFREX
AFREX
AFTEN
AFTFM
AFTFM
CTRFC
AFTRL
AFTEG
AFTEG
AFTEG
AFTEG
AFTEG
AFTEG
AFCS1
AFTEG
Bank funds expended to date on project preparation:
1. Bank resources:
~US$1,500,000
2. Trust funds:
None
3. Total:
~US$1,500,000
Estimated Supervision costs:
Estimated annual supervision cost: US$400,000
220
Annex 13: Documents in the Project File
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
1. Alpha-Charlie (Medupi Power Plant), Business Case, 2005
2. Assessing the macro-economic impact of Eskom’s Planned R343 billion capital expenditure
on the South African economy, Eskom/BER/CITI, 2008
3. CSP Information Document, Eskom 2009
4. CTF Investment Plan, November 2009
5. Deloitte Report on Eskom Electricity Sector, 2008
6.
Electricity Pricing Policy, 2008
7. Eskom Financial Statements and Projections (Dashboard), 2009-10
8. Eskom Long-term Transmission Plans – Presentation to World Bank – November 2008
9. Eskom Medupi Project Independent Assessment – Nexant LLC (USA) – March 2010
10. Expert Panel Report on Project Consistency with Development and Climate Change Strategic
Framework – January 2010
11. Hendrina/Matimba Project Information Note
12. Independent Review of Compliance with Equator Principles, SE Solutions (Pty) Ltd.
13. Integrated System Expansion Plan, 2009
14. Long Term Mitigation Scenario, Strategic Options for South Africa – Department of
Environmental Affairs – South Africa, October 2007
15. Majuba Rail Economic Analysis – Richard Bullock – December 2009
16. MCWAP EIA Scoping Report (http://www.dwa.gov.za/Projects/MCWAP/EIA.aspx)
17. Medupi Economic Analysis – Peter Meier – December 2009
18. Mokolo and Crocodile Water Augmentation Project – DWAF Presentation to World Bank –
December 2009
19. Multi-Year Tariff Determination 2, Eskom November 2009
20. Review of Medupi Contracts – Armando Araujo – February 2010
21. Safeguards Diagnostic Review – World Bank – January 2010
22. SAPP Regional Generation and Transmission Expansion Plan Study, Nexant of USA.
23. Social Impact of Electricity Tariffs, Diego Bondorevsky, 2009
24. South Africa Electrification Program – Electrification Statistics, 2009
25. South Africa Nuclear Energy Policy, 2008
26. Various Presentation, Energy Efficiency and DSM, 2009
221
Annex 14: Statement of Loans and Credits
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Difference between
expected and actual
disbursements
Original Amount in US$ Millions
Project ID
FY
Purpose
IBRD
Total:
IDA
0.00
0.00
SF
GEF
0.00
Cancel.
Undisb.
0.00
0.00
0.00
Orig.
Frm. Rev’d
0.00
0.00
STATEMENT OF IFC’s
Held and Disbursed Portfolio
In Millions of US Dollars
Committed
Disbursed
IFC
FY Approval
IFC
Company
Loan
Equity
Quasi
Partic.
1999
AEF Dargle Timbr
0.37
0.00
0.00
0.00
0.37
0.00
0.00
0.00
1999
AEF IHS Techno
0.00
0.00
0.22
0.00
0.00
0.00
0.22
0.00
2000
AEF Tusk
1.61
0.00
0.00
0.00
1.61
0.00
0.00
0.00
2004
African Bank
2.39
0.00
0.00
0.00
0.89
0.00
0.00
0.00
2002
Bioventures
0.00
2.17
0.00
0.00
0.00
1.51
0.00
0.00
2006
Buffalo City
5.87
0.00
0.00
0.00
5.87
0.00
0.00
0.00
2004
City of Johannes
29.00
0.00
0.00
0.00
29.00
0.00
0.00
0.00
2000
EDU LOAN
1.16
0.00
0.00
0.00
1.16
0.00
0.00
0.00
2006
Ethos V
0.00
25.00
0.00
0.00
0.00
1.91
0.00
0.00
2005
FirstRand Lim...
0.00
0.00
26.70
0.00
0.00
0.00
26.70
0.00
Formeset
1.23
0.00
0.00
0.00
1.23
0.00
0.00
0.00
2004
Hernic
23.02
4.70
1.99
0.00
23.02
4.70
1.93
0.00
2006
Hernic
3.73
0.00
1.52
0.00
0.00
0.00
0.60
0.00
2006
Karsten Farms
6.67
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Kunene
0.00
0.67
0.00
0.00
0.00
0.67
0.00
0.00
Mvela Gold
0.00
0.00
36.93
0.00
0.00
0.00
36.93
0.00
2002
NAMF
0.00
3.47
0.00
0.00
0.00
2.08
0.00
0.00
2000
SAHL
0.00
2.19
0.00
0.00
0.00
2.11
0.00
0.00
2003
SAHL
0.00
4.19
0.00
0.00
0.00
4.19
0.00
0.00
2004
SAHL
0.00
0.66
0.00
0.00
0.00
0.66
0.00
0.00
2004
Loan
Equity
Quasi
Partic.
2005
SAHL
0.00
0.00
1.29
0.00
0.00
0.00
1.29
0.00
1999
SAPEF
0.00
0.25
0.00
0.00
0.00
0.00
0.00
0.00
Sphere I
0.00
4.65
0.00
0.00
0.00
0.45
0.00
0.00
0.19
0.00
0.00
12.43
0.19
0.00
0.00
48.14
68.65
0.00
75.58
18.47
67.67
0.00
2001
Spier
12.43
Total portfolio:
87.48
222
Annex 15: Country at a Glance
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
P O V E R T Y a nd S O C IA L
2007
P o pulatio n, mid-year (millio ns)
GNI per capita (A tlas metho d, US$ )
GNI (A tlas metho d, US$ billio ns)
S o ut h
A f ric a
S ubS a ha ra n
A f ric a
Uppe rm iddle inc o m e
47.6
5,760
274.0
800
952
762
823
6,987
5,750
1.0
1.0
2.5
2.6
0.7
1.3
..
60
51
56
..
93
..
106
108
103
..
36
51
94
27
58
59
94
99
88
..
75
71
22
..
95
93
111
112
109
D e v e lo pm e nt dia m o nd*
Life expectancy
A v e ra ge a nnua l gro wt h, 2 0 0 1- 0 7
P o pulatio n (%)
Labo r fo rce (%)
M o s t re c e nt e s t im a t e ( la t e s t ye a r a v a ila ble , 2 0 0 1- 0 7 )
P o verty (% o f po pulatio n belo w natio nal po verty line)
Urban po pulatio n (% o f to tal po pulatio n)
Life expectancy at birth (years)
Infant mo rtality (per 1,000 live births)
Child malnutritio n (% o f children under 5)
A ccess to an impro ved water so urce (% o f po pulatio n)
Literacy (% o f po pulatio n age 15+)
Gro ss primary enro llment (% o f scho o l-age po pulatio n)
M ale
Female
GNI
per
capita
Gro ss
primary
enro llment
A ccess to impro ved water so urce
So uth A frica
Upper-middle-inco me gro up
KE Y E C O N O M IC R A T IO S a nd LO N G - T E R M T R E N D S
19 8 7
19 9 7
2006
2007
104.0
148.8
255.0
277.6
15.8
30.3
25.7
22.5
16.6
24.6
17.8
15.1
20.5
29.8
17.1
13.9
20.1
30.3
16.4
13.4
2.8
..
..
..
..
..
-1.5
0.6
17.0
17.2
..
..
-6.5
0.5
13.9
6.7
14.1
43.9
-6.4
..
..
..
..
..
19 8 7 - 9 7 19 9 7 - 0 7
2006
2007
2 0 0 7 - 11
3.7
2.2
3.6
5.0
3.9
5.5
4.8
4.4
7.0
4.6
4.5
5.5
19 8 7
19 9 7
2006
2007
GDP (US$ billio ns)
Gro ss capital fo rmatio n/GDP
Expo rts o f go o ds and services/GDP
Gro ss do mestic savings/GDP
Gro ss natio nal savings/GDP
Current acco unt balance/GDP
Interest payments/GDP
To tal debt/GDP
To tal debt service/expo rts
P resent value o f debt/GDP
P resent value o f debt/expo rts
E c o no m ic ra t io s *
Trade
Do mestic
savings
Capital
fo rmatio n
Indebtedness
(average annual gro wth)
GDP
GDP per capita
Expo rts o f go o ds and services
1.3
-0.8
4.7
So uth A frica
Upper-middle-inco me gro up
S T R UC T UR E o f t he E C O N O M Y
(% o f GDP )
A griculture
Industry
M anufacturing
Services
5.6
41.7
22.4
52.7
4.0
32.7
19.9
63.3
2.7
30.9
18.2
66.4
2.7
30.9
18.2
66.4
Ho useho ld final co nsumptio n expenditure
General go v't final co nsumptio n expenditure
Impo rts o f go o ds and services
55.1
19.2
20.3
63.0
19.2
23.4
63.5
19.5
33.2
63.7
19.9
34.0
19 8 7 - 9 7 19 9 7 - 0 7
2006
2007
G ro wt h o f c a pit a l a nd G D P ( %)
20
15
10
5
0
-5
02
03
04
05
GCF
06
07
GDP
G ro wt h o f e xpo rt s a nd im po rt s ( %)
(average annual gro wth)
A griculture
Industry
M anufacturing
Services
-0.1
0.4
0.4
1.8
0.6
2.8
3.2
4.4
-13.1
4.3
4.8
5.9
4.8
4.8
4.8
4.8
20
Ho useho ld final co nsumptio n expenditure
General go v't final co nsumptio n expenditure
Gro ss capital fo rmatio n
Impo rts o f go o ds and services
1.3
1.2
3.3
6.9
4.1
4.3
6.4
6.5
7.8
5.4
15.5
18.4
3.8
8.7
6.4
7.6
0
15
10
5
02
03
04
Exports
05
06
07
Import s
No te: 2007 data are preliminary estimates.
This table was pro duced fro m the Develo pment Eco no mics LDB database.
* The diamo nds sho w fo ur key indicato rs in the co untry (in bo ld) co mpared with its inco me-gro up average. If data are missing, the diamo nd will
be inco mplete.
223
South Africa
P R IC E S a nd G O V E R N M E N T F IN A N C E
19 8 7
D o m e s t ic pric e s
(% change)
Co nsumer prices
Implicit GDP deflato r
G o v e rnm e nt f ina nc e
(% o f GDP , includes current grants)
Current revenue
Current budget balance
Overall surplus/deficit
19 9 7
2006
2007
Inf la t io n ( %)
15
17.1
14.5
8.6
8.1
4.7
6.8
6.3
8.1
10
5
0
23.9
-3.0
-6.3
28.0
-2.1
-4.7
26.9
1.6
0.4
27.4
2.0
0.8
02
03
04
05
GDP def lator
06
07
CPI
TRADE
(US$ millio ns)
To tal expo rts (fo b)
Go ld
Co al mining
M anufactures
To tal impo rts (cif)
Fo o d
Fuel and energy
Capital go o ds
Expo rt price index (2000=100)
Impo rt price index (2000=100)
Terms o f trade (2000=100)
19 8 7
19 9 7
2006
2007
25,964
10,512
1,261
9,833
15,574
602
1,694
2,651
36,607
5,596
2,130
18,581
31,398
1,453
2,269
5,854
75,171
4,922
3,265
44,081
71,243
2,328
6,854
12,237
81,806
5,356
3,553
47,972
77,531
2,534
7,459
13,317
128
113
114
112
105
107
115
111
104
107
108
100
E xpo rt a nd im po rt le v e ls ( US $ m ill.)
100,000
80,000
60,000
40,000
20,000
0
01
02
03
04
Export s
05
06
07
Import s
B A LA N C E o f P A Y M E N T S
19 8 7
19 9 7
2006
2007
(US$ millio ns)
Expo rts o f go o ds and services
Impo rts o f go o ds and services
Reso urce balance
23,557
17,292
6,265
36,607
34,883
1,724
76,155
84,746
-8,591
82,877
92,246
-9,369
2
Net inco me
Net current transfers
-3,542
210
-3,222
-722
-5,284
-2,733
-5,089
-3,275
-2
Current acco unt balance
2,934
-2,221
-16,608
-17,733
Financing items (net)
Changes in net reserves
-1,587
-1,347
108
2,113
12,206
4,402
14,733
3,000
M emo :
Reserves including go ld (US$ millio ns)
Co nversio n rate (DEC, lo cal/US$ )
3,900
1.7
5,848
4.6
25,613
6.8
28,613
7.0
19 9 7
2006
2007
25,272
0
0
35,549
29
0
..
27
0
C urre nt a c c o unt ba la nc e t o G D P ( %)
0
01
02
03
04
05
06
07
-4
E X T E R N A L D E B T a nd R E S O UR C E F LO WS
19 8 7
(US$ millio ns)
To tal debt o utstanding and disbursed
..
IB RD
..
IDA
..
To tal debt service
IB RD
IDA
..
..
..
6,542
0
0
5,472
3
0
..
4
0
Co mpo sitio n o f net reso urce flo ws
Official grants
Official credito rs
P rivate credito rs
Fo reign direct investment (net inflo ws)
P o rtfo lio equity (net inflo ws)
..
..
..
..
..
200
0
-51
3,811
5,473
339
23
1,024
-120
14,959
..
..
..
..
..
Wo rld B ank pro gram
Co mmitments
Disbursements
P rincipal repayments
Net flo ws
Interest payments
Net transfers
..
..
..
..
..
..
0
0
0
0
0
0
0
0
2
-2
1
-3
0
0
3
-3
1
-4
No te: This table was pro duced fro m the Develo pment Eco no mics LDB database.
224
-6
-8
C o m po s it io n o f 2 0 0 6 de bt ( US $ m ill.)
A: 29
D: 313
G: 15,260
F: 19,947
A - IBRD
B - IDA
C - IM F
D - Other mult ilateral
E - Bilateral
F - Privat e
G - Short -t erm
9/24/08
Economic and Social Indicators
South Africa
Balance of Payments and Trade
2000
2008
Governance indicators, 2000 and 2007
(US$ millions)
Total merchandise exports (fob)
Total merchandise imports (cif)
Net trade in goods and services
Current account balance
as a % of GDP
Workers' remittances and
compensation of employees (receipts)
Reserves, including gold
37,058
29,757
3,930
87,378
83,514
-8,567
Voice and accountability
-172
-0.1
-20,474
-7.4
Regulatory quality
344
834
7,533
34,099
Political stability
Rule of law
Control of corruption
0
Central Government Finance
(% of GDP)
Current revenue (including grants)
Tax revenue
Current expenditure
22.9
22.5
23.5
26.8
26.2
27.4
Overall surplus/deficit
-1.9
-1.0
Highest marginal tax rate (%)
Individual
Corporate
45
30
25
50
75
100
2007
Country's percentile rank (0-100)
2000
higher values imply better ratings
Source: Kaufmann-Kraay-Mastruzzi, World Bank
40
28
Technology and Infrastructure
2000
2007
Paved roads (% of total)
Fixed line and mobile phone
subscribers (per 100 people)
High technology exports
(% of manufactured exports)
20.3
..
30
98
7.0
5.7
82
7.6
..
82
7.6
6.1
990
12.5
936
..
CO2 emissions per capita (mt)
8.4
8.7
GDP per unit of energy use
(2005 PPP $ per kg of oil equivalent)
3.0
3.2
2,529
2,739
2000
2007
IBRD
Total debt outstanding and disbursed
Disbursements
Principal repayments
Interest payments
3
3
0
0
29
0
2
1
IDA
Total debt outstanding and disbursed
Disbursements
Total debt service
0
0
–
0
0
–
55
55
25
166
166
27
3
28
12
0
12
0
External Debt and Resource Flows
Environment
(US$ millions)
Total debt outstanding and disbursed
Total debt service
Debt relief (HIPC, MDRI)
Total debt (% of GDP)
Total debt service (% of exports)
Foreign direct investment (net inflows)
Portfolio equity (net inflows)
24,861
3,861
–
35,549
4,554
–
18.7
9.8
13.8
4.4
617
-7,861
12,528
-15,919
Composition of total external debt, 2007
are not available)
IDA,
IMF,00
Agricultural land (% of land area)
Forest area (% of land area)
Nationally protected areas (% of land area)
Freshwater resources per capita (cu. meters)
Freshwater withdrawal (billion cubic meters)
(data
Energy use per capita (kg of oil equivalent)
IBRD, 0
Short-term,
16,558
World Bank Group portfolio
(US$ millions)
Other multilateral, -29,509
Private, 12,951
Bilateral, 0
US$ millions
Private Sector Development
2000
2008
–
–
–
22
6.0
24
Ranked as a major constraint to business
(% of managers surveyed who agreed)
Skills and education of workers
Labor regulations
2000
2007
..
..
35.5
32.8
Stock market capitalization (% of GDP)
Bank capital to asset ratio (%)
154.2
8.7
293.8
7.9
Time required to start a business (days)
Cost to start a business (% of GNI per capita)
Time required to register property (days)
IFC (fiscal year)
Total disbursed and outstanding portfolio
of which IFC own account
Disbursements for IFC own account
Portfolio sales, prepayments and
repayments for IFC own account
MIGA
Gross exposure
New guarantees
Note: Figures in italics are for years other than those specified. 2008 data are preliminary.
.. indicates data are not available. – indicates observation is not applicable.
Development Economics, Development Data Group (DECDG).
225
9/3/09
Millennium Development Goals
South Africa
With selected targets to achieve between 1990 and 2015
South Africa
(estimate closest to date shown, +/- 2 years)
Goal 1: halve the rates for extreme poverty and malnutrition
Poverty headcount ratio at $1.25 a day (PPP, % of population)
Poverty headcount ratio at national poverty line (% of population)
Share of income or consumption to the poorest qunitile (%)
Prevalence of malnutrition (% of children under 5)
1990
..
..
..
..
1995
21.4
..
3.6
9.2
2000
26.2
..
3.5
11.5
2007
..
..
..
..
90
76
66
..
..
..
83
94
90
90
86
..
87
92
96
..
104
43
3
..
44
25
101
45
30
101
46
33
Goal 4: reduce under-5 mortality by two-thirds
Under-5 mortality rate (per 1,000)
Infant mortality rate (per 1,000 live births)
Measles immunization (proportion of one-year olds immunized, %)
60
45
79
59
45
76
63
50
77
68
55
82
Goal 5: reduce maternal mortality by three-fourths
Maternal mortality ratio (modeled estimate, per 100,000 live births)
Births attended by skilled health staff (% of total)
Contraceptive prevalence (% of women ages 15-49)
..
..
57
..
82
..
230
84
56
..
92
60
Goal 6: halt and begin to reverse the spread of HIV/AIDS and other major diseases
Prevalence of HIV (% of population ages 15-49)
Incidence of tuberculosis (per 100,000 people)
Tuberculosis cases detected under DOTS (%)
0.8
224
..
6.2
392
5
15.9
536
62
18.1
600
103
Goal 7: halve the proportion of people without sustainable access to basic needs
Access to an improved water source (% of population)
Access to improved sanitation facilities (% of population)
Forest area (% of total land area)
Nationally protected areas (% of total land area)
CO2 emissions (metric tons per capita)
GDP per unit of energy use (constant 2005 PPP $ per kg of oil equivalent)
83
69
7.6
..
9.4
3.0
84
68
..
..
9.0
2.7
87
66
7.6
..
8.4
3.0
88
65
7.6
6.1
8.7
3.2
Goal 8: develop a global partnership for development
Telephone mainlines (per 100 people)
Mobile phone subscribers (per 100 people)
Internet users (per 100 people)
Personal computers (per 100 people)
9.4
0.0
0.0
0.7
10.2
1.4
0.7
2.8
11.3
19.0
5.5
6.6
9.7
88.4
8.3
8.5
Goal 2: ensure that children are able to complete primary schooling
Primary school enrollment (net, %)
Primary completion rate (% of relevant age group)
Secondary school enrollment (gross, %)
Youth literacy rate (% of people ages 15-24)
Goal 3: eliminate gender disparity in education and empower women
Ratio of girls to boys in primary and secondary education (%)
Women employed in the nonagricultural sector (% of nonagricultural employment)
Proportion of seats held by women in national parliament (%)
Education indicators (%)
Measles immunization (% of 1-year olds)
ICT indicators (per 100 people)
125
100
120
100
100
75
75
80
50
60
50
25
40
25
0
20
2000
2002
2004
2006 2007
0
0
1990
1995
2000
2007
2000
2002
2004
2006 2007
Primary net enrollment ratio
Ratio of girls to boys in primary & secondary
education
South Africa
Sub-Saharan Africa
Note: Figures in italics are for years other than those specified. .. indicates data are not available.
Fixed + mobile subscribers
Internet users
9/3/09
Development Economics, Development Data Group (DECDG).
226
-2.1
7.5
Table 16: National Government Main Budget (2004/05-2010/11)1
2007/08
2008/09
2009/10
(proj.)
2010/11
(proj.)
2004/05
2005/06
2006/07
24.0
25.5
26.2
26.9
26.2
23.3
23.8
24.5
25.9
27.0
27.5
26.9
24.1
24.0
13.8
14.6
15.6
16.3
16.9
14.7
14.3
(in percent of GDP)
Total revenue and grants
Tax revenue
Income tax
of which Personal income tax
7.7
7.8
7.7
8.1
8.4
8.3
8.3
5.8
6.5
7.5
7.8
8.1
6.1
5.7
10.7
11.2
11.4
11.2
10.1
9.4
9.7
6.8
7.1
7.3
7.2
6.7
6.0
6.1
Excise duties
2.3
2.3
2.2
2.1
2.0
2.2
2.4
Taxes on international trade
0.9
1.1
1.3
1.3
1.0
0.8
0.8
Other tax revenue
0.1
0.0
0.0
0.0
0.0
0.0
0.0
SACU payments
0.9
0.9
1.4
1.2
1.2
1.1
0.6
Nontax revenue
0.4
0.5
0.6
0.6
0.5
0.4
0.4
Grants
0.0
0.0
0.0
0.0
0.0
0.0
0.0
25.4
25.8
25.6
26.0
27.4
30.6
30.3
Interest
3.4
3.2
2.8
2.5
2.3
2.4
2.6
Transfers and subsidies
8.7
9.2
9.7
10.3
10.7
11.4
11.2
-1.4
-0.3
0.6
0.9
-1.2
-7.2
-6.5
Corporate tax
Indirect tax
of which VAT
Total expenditure
Budget balance
Net extraordinary payments
-0.5
0.1
0.0
0.1
0.2
0.2
0.0
Augmented balance
-1.9
-0.2
0.6
1.0
-1.0
-7.0
-6.5
1.9
0.2
-0.6
-1.0
1.0
7.0
6.5
2.7
1.8
0.3
0.2
1.5
6.7
5.9
Financing
Net domestic borrowing
Foreign loans (net)
Change in cash and other balances
0.3
0.0
0.0
-0.2
-0.2
0.4
0.4
-1.1
-1.7
-0.9
-0.9
-0.3
-0.1
0.1
Memorandum items:
GDP (R billion)
1,449
1,614
1,833
2,082
2,320
2,450
2,700
Real GDP growth (%)
4.6
5.3
5.6
5.5
3.7
-1.8
2.3
GDP deflator (% )change
6.4
5.4
6.5
8.2
9.2
7.4
6.6
Primary balance, (% of GDP)
1.9
2.8
3.4
3.4
1.2
-4.9
-3.8
Debt (% of GDP)
Domestic
Foreign
34.6
32.7
30.2
27.7
27
32.5
37.1
29.8
28.6
25.7
23.1
22.8
28.7
33.1
4.8
4.1
4.5
4.6
4.2
3.8
3.9
Source: Ministry of Finance
1
For fiscal year beginning April 1. National government comprises the central government and sub-national spending financed by transfers from the national revenue
fund.
227
1
Table 2: Nonfinancial Public Sector Operations, 2004/05-2010/11
2004/05
2005/06
2006/07 2007/08
2008/09 2009/10
proj.
2010/11
proj.
(In percent of GDP)
General government (excl. local governments)
Total revenue and grants
National government
Provinces (own revenue)
Social security funds (own revenue)
Extrabudgetary and other
2
25.9
24.0
0.4
1.0
0.1
27.7
25.5
0.4
1.3
0.1
28.7
26.2
0.4
1.1
0.1
30.2
26.9
0.5
1.2
0.0
29.7
26.2
0.4
1.1
0.0
26.8
24.1
0.4
1.3
0.0
27.7
24.0
0.4
1.3
0.0
26.8
25.7
9.0
3.5
3.4
9.8
1.1
0.1
27.5
26.2
9.8
3.7
3.5
9.2
1.3
0.0
27.5
26.0
9.3
4.9
3.0
9.3
1.3
0.0
28.5
26.2
9.4
4.9
2.7
9.8
1.3
0.0
30.8
27.6
10.0
5.4
2.5
10.2
1.4
0.0
34.1
29.8
11.1
6.0
2.9
11.0
1.4
0.2
34.0
28.6
10.9
5.8
3.2
10.5
1.4
0.4
-0.9
0.3
1.2
1.7
-1.0
-7.3
1.5
1.9
0.0
-0.1
0.6
-0.5
-0.4
0.4
0.2
0.2
0.0
0.6
-0.3
-0.4
-0.5
-0.6
-0.3
0.0
0.0
-0.3
0.6
-0.3
-1.0
-0.2
-0.1
0.3
-0.4
1.2
4.0
1.0
0.7
0.4
0.9
-0.5
2.3
11.8
7.0
0.4
0.0
0.5
-0.2
4.2
11.2
6.5
0.1
-0.1
0.6
-0.3
4.3
43.3
1.7
13.9
1.5
40.4
1.4
13.2
1.6
38.1
1.2
14.6
1.4
35.3
3.7
15.7
1.3
42.8
4.4
16.1
1.4
46.5
4.7
16.1
1.3
Total expenditure
Current
Wages and salaries
Other goods and services
Interest
Transfers
Capital expenditure
Net lending
Overall balance
Public sector borrowing requirement (PSBR)
3
National government
Other government borrowing
Provincial governments
Local government and local enterprises
Extrabudgetary funds and institutions
Nonfinancial public enterprises
Memorandum items:
Non-financial public sector debt (gross)
SOE investment
4
Social spending
Defense spending
Sources: Ministry of Finance.
1
For fiscal year beginning April 1.
2
Consolidated national and provincial governments.
3
Includes extraordinary payments less extraordinary receipts.
4
Health, education, welfare, and community development.
228
35.4
2.8
14.7
1.3
-6.2
Table 3: Financial Soundness Indicators, 2004-09
2004
2005
2006
2007
2008
20091
(Percentage, unless otherwise indicated)
Capital adequacy:
Regulatory capital to risk-weighted assets2
14.0
12.7
12.3
12.8
13.0
13.5
Regulatory tier 1 capital to risk-weighted assets3
10.5
9.7
9.0
9.5
10.2
10.5
1.8
1.5
1.1
1.4
3.9
5.1
Asset quality:
Nonperforming loans to total gross loans3
3
Nonperforming loans net of provisions to capital
6.2
6.4
5.6
8.2
43.3
46.2
47.7
48.9
48.8
48.9
Return on assets (average)
1.3
1.2
1.4
1.4
2.1
1.0
Return on equity (average)
16.2
15.2
18.3
18.1
28.7
17.8
Interest margin to gross income
41.6
38.2
43.8
58.5
44.6
50.6
Non-interest expenses to gross income
68.5
61.5
48.5
48.9
42.2
49.8
Share of mortgage advances in domestic private credit4
Earnings and profitability:
Exposure to FX risk:
Liquid assets to total assets
Share of short-term deposits in total deposits
Maximum effective net open FX position to capital
Share of foreign currency loans in total lending
5
4.7
4.8
4.6
4.6
4.7
5.3
43.7
43.5
42.8
42.5
36.4
35.0
0.8
1.9
1.4
0.7
0.5
0.5
10.9
11.1
11.4
9.3
7.7
6.9
Share of foreign currency deposits in total deposits
2.7
2.7
3.3
3.0
3.6
3.6
Share of foreign liabilities in total liabilities6
4.0
4.2
5.3
6.0
6.2
6.3
Source: IMF, Article IV Consultation 2009
1
As of March/April 2009
2
Total (banking and trading book)
3
The official definition of nonperforming loans comprises doubtful and loss loans. Doubtful are loans overdue for 180 days unless well secured, or with a timely
realization of the collateral. Since 2008, the indicator reflects the ratio of impaired advances to total advances (in line with Basel II definitions), a more stringent
definition.
4
Domestic private credit not seasonally adjusted
5
Foreign funding to total funding
6
Foreign funding to total liabilities (including capital)
229
Annex 16: Maps
SOUTH AFRICA: ESKOM INVESTMENT SUPPORT PROJECT
Page Intentionally Left Blank
230
SOUTH AFRICA
20°E
24°E
22°E
26°E
28°E
ESKOM INVESTMENT
SUPPORT PROJECT (EISP)
To
Mazunga
22°S
PROJECT:
SITES
To
Serowe
B O T S WA N A
TRANSMISSION LINE CORRIDORS
24°S
To
Kanye
PROVINCE CAPITALS
NATIONAL CAPITAL
RAILROADS
PROVINCE BOUNDARIES
Witdraal
18°E
To
Karasburg
NAMIBIA
Hotazel
Candidate
Concentrated
Solar Power Site
Ermelo
To
Mbabane
To
Siteki
For detail, see IBRD 37482.
Newcastle
Bitterfontein
Calvinia
r
s
b
Durban
30°S
e
Aiwal North
D
Middleburg
Victoria West
OCE AN
n
De Aar
Britsown
I N DI AN
Richards Bay
Ulundi
(Pietermaritzburg)
e
ng
Mafadi
(3451 m)
g
To
Maseru
on
ra
Cal
ed
O
e
NORTHERN CAPE
G r o a t
Vl o e r
30°S
K WA Z U L U N ATA L
LESOTHO
Prieska
28°S
Ladysmith
Bloemfontein
Port Nollth
Coal Transportation Railway
Ulundi
Harrismith
F R E E S TAT E
Kimberley
26°S
SW
SWAZILAND
Vryheid
Kenhardt
Springbok
To
Maputo
Standerton
Kroonstad
Upington
Orange
r
a
k Kokstad
Port Shepstone
Umtata
Queenstown
Vanrhynsdorp
EASTERN CAPE
Beaufort
West
GraaffReinet
AT LAN TI C
32°S
Bisho
WESTERN CAPE
Saldanha
Worcester
Cape Town
Paarl
t
Grea
Oudtshoor
Swellendam
Kar
ro
o
SOUTH
AFRICA
Uitenhage
George
Port Elizabeth
0
This map was produced by the Map Design Unit of The World Bank.
The boundaries, colors, denominations and any other information
shown on this map do not imply, on the part of The World Bank Group,
any judgment on the legal status of any territory, or any endorsement or
acceptance of such boundaries.
Cape of
Good Hope
0
Cape Agulhas
18°E
20°E
22°E
24°E
26°E
28°E
100
200 Kilometers
100
30°E
34°S
200 Miles
32°E
34°E
36°E
IBRD 37164R
JANUARY 2010
Mosselbaai
16°E
Bethel
Sishen
Keimoes
14°E
24°S
Bethlehem
To
Karasburg
Wind Farm
ts
MPUMALANGA
Vereeniging
al
Va
rts
Ha
Olifan
Middleburg
Springs
NORTH WEST
Reitfontein
INTERNATIONAL BOUNDARIES
PRETORIA
Mmabatho
Johannesburg
26°S
MAIN ROADS
34°S
OZ AM B IQ
UE
M OZAM
I QUE
Nelspruit
Rustenburg
RIVERS
OCEAN
22°S
WATERBERG
DISTRICT COUNCIL T r a n s v a a l
GAUTENG
CITIES AND TOWNS
32°S
To
Nuanetsi
Polokwane
(Pietersburg)
Waterberg
Biosphere
To
Mochudi
ENVIRONMENTAL MANAGEMENT
FRAMEWORK BY NATIONAL GOVERNMENT
28°S
34°E
Medupi Power Plant
NATIONAL ENERGY EFFICIENCY
IMPROVEMENTS (NATIONWIDE)
16°E
32°E
LIMPOPO
Lephalale
po
po Local Municipality
Li m
COAL TRANSPORTION RAILWAY
14°E
30°E
ZI M B
AB W E
BAB
28°00’
28°30’
29°00’
29°30’
SOUTH AFRICA
to Stoffberg
Pretoria
Silverton
Wilge R.
Bronkhorstspruit
Middelburg
to Machadodorp
MAJUBA RAIL LINE
Klein-Kom
.
ati R.
rs R
naa
Pie
Machadodorp
ESKOM INVESTMENT
SUPPORT PROJECT (EISP)
Belfast
Witbank
Uitkyk
PROJECT 3 kV DC RAILWAY,
ERMELO TO MAJUBA
3 kV DC RAILWAYS
R.
Groengoeverden
Steenkool R.
d R.
MPUMALANGA
Tricha
r
Chrissiesmeer
Breyten
Eilandsmeer
Nigel
Lake Banagher
Bethal
Heidelbe
Heidelberg
H
id lb
kR
.
an
sbo
osr
Ble
rb
ike
Su
Waterv
a
.
S O U T Hand R
r
AFRICA
bos
ker
Sui
W.B. Douglas Res.
Secunda
.
dR
l R.
Mey t
Meyerton
Me
Davel
Trichardt
Balfour
.
tu R
Usu
Ermelo
Ermelo Yard
Sasol
26°30’
Vaal R
.
Riet R.
26°30’
R.
Kliprivier
uzi
Leandra
Dunnottar
pul
Matta
30°30’
uM
ts R.
Alberton
Elders
Kriel
to Carolina
30°00’
Hendrina
Olifan
Springs
CarolinaCOAL MINES WHICH WILL SUPPLY MAJUBA
Komati
Leeuwpan
Seekoei R.
THERMAL POWER PLANTS
R.
Wilge
Johannesburg
Benoni
PRIVATE SIDINGS
Koornfontein
Kendal
DERELICT RAILWAYS (CLOSED/REMOVED)
26°00’
Komati
R.
fie
Kof
Ogies
ts R.
R.
Delmas
Olifan
horst
Rosebank
Arbor
DIESEL RAILWAYS
Klein-
Bapsfontein
Randburg
New Largo
Bronk
GAUTENG
Komati R.
25 kV AC RAILWAYS
Witbank Lake
26°00’
IBRDs 37482
R.
Eland
.
Vaal R
sR
.
Jericho Res.
esm
an
Greylingstad
Morgenzon
Bo
28°30’ to Bethlehem
28°00’
Tutuka
ZIM.
BOTSWANA
Deneysville
Over Vaal
Tunnel
MOZ.
Klein
FREE STATE
Vaal Lake
LESOTHO
al
Vaal R.
MINOR PROVINCIAL AND LOCAL ROADS
Groot
Lake
Vaal R.
Villiers
to Piet
Retief
PRIMARY AND MAJOR PROVINCIAL ROADS
Amersfoort
KWAZULUNATAL
Kli
NORTHERN CAPE
Standerton
27°00’
SOUTH AFRICA
.
isi R
mp
e
Ngw
Wa
te
SWA.
Riet R.
MP
UM
A
LAN
GA
Area of main map
GAUTENG PRETORIA
Oranjeville
NORTH WEST
l R.
rva
NAMIBIA
-Vaa
Vaal R.
R.
LIMPOPO
NATIONAL ROADS
27°00’
PROVINCE BOUNDARIES
CITIES AND TOWNS
Heyshope
Res.
NATIONAL CAPITAL
EASTERN CAPE
OCEAN
WESTERN CAPE
Heilbron
Klip
R.
F R E E S TAT E
I N D I AN
O CE AN
Frankfort
0
10
20
30
KILOMETERS
aai
Sku
ATLANTIC
lp R
.
.
pR
Majuba
40
to Vrede
50
eg
Ass
Palmford
29°30’
Sand R.
to Volksrust
30°00’
R.
This map was produced by the Map Design Unit of The World Bank.
The boundaries, colors, denominations and any other information shown on
this map do not imply, on the part of The World Bank Group, any judgment
on the legal status of any territory, or any endorsement or acceptance of
such boundaries.
30°30’
JANUARY 2010